Oil and GasFall 1997-Professor Smith

Kevin T. Jacobs

I. DOCTRINES CONCERNING DRILLING AND PRODUCTION OF OIL & GAS

A. U.S. Oil and Gas Production

Legal doctrines: Impacts.1. Can we continue producing, but they can also have an adverse affect on the environment2. How efficiently production will be obtained from a particular field.

B. Geological Background

1. Origin of petroleum - Two main theories

a. Organic Theory

Organic in origin, resulting from the accumulation of microscopic animals in shallow seas. These microorganisms were overlaid with silt and they changed as a result of pressure, etc. The liquified accumulation sank and then became overlaid with rock. Then the "oil" seeped into the porous rock, where it lies today. Under this theory, all of the O&G that exists had been discovered, and the supply is finite.

Method: Look for where crustacean seas existed.

b. Gould's Theory [Inorganic Theory]

His theory originated from the discovery of hydrocarbons in meteorites, even though there was no organic life. Under this theory, methane gas, heavily present in the Earth, is transformed into petroleum and migrates up towards the surface. Thus, hydrocarbons were present on earth from the beginning, and through pressure became petroleum and ended up where they are now. Under this theory, hydrocarbons are virtually

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inexhaustible.

Method: Look for deep fisures in the earth.

c. Comments

Depending on which theory is used, this will influence a decision of where to drill. Under Gould's theory, one can drill anywhere if well is deep enough. Most geologists, however, adhere to the organic theory.

2. Components of Petroleum Reservoirs - Organic Theory

In order for an oil and gas field to have been formed, there must have been the following.

a. A source of carbon and hydrogen that developed from the remains of land and sea life buried in the mud and silt of ancient seas.

b. Conditions that caused the decay or decomposition of these remains and the recombining of carbon and hydrogen to form the mixture of hydrocarbons that make up petroleum.

c. A porous rock or series of such rocks within which the petroleum was able to migrate and displace the water originally in the rock.

NOTE: Oil is never just "sitting there;" it is absorbed in porous rock. If the stratus is porous but not very permeable (i.e., "tight"), then the driller will need to use an artificial method to increase permeability in the stratum.

d. A local structure or trap, having a top layered seal, that forms a reservoir where petroleum has gathered.

3. Types of Reservoirs

Grouped according to the conditions causing their occurence.

a. Domes and anticlines

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These are reservoirs formed by folding of the rock layers or strata, and usually have the shape of structural domes.

b. Syncline or reverse dome

As suggested, these are an inverted dome.

The distinction between the these first two is mainly in the location of the gas. In the syncline, the gas is around the edges. In the anticline the gas is in the center. Being light, gas always moves to the highest point in the reservoir.

c. Salt Domes (in anitcline or faulted reservoir)Indicates several reservoirsstacked on top of each other. This reservoir consists of pockets of oil in almost impervious rock creating 2 major problems:

(1) difficult to find(2) very small pockets.

Thus, risky venture w/ low return.

d. Fault traps

Discontinuos pockets of oil in otherwise impervious material

These are formed by breaking or shearing and offsetting of strata (faulting).

The escape of the oil is prevented by impervious rocks that have moved into a position opposite the porous petroleum-bearing formation. The oil is confined in traps of this type because of the tilt of the rock layers.

This type of reservoir, in contrast to the first two (which are single reservoirs) can give a series of pockets of oil, perhaps at different levels along the fault line. This type of reservoir requires more wells, is difficult to acquire accurate and comprehensive geologic information on, and results in more dry holes.

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*Two conditions that would make drilling these worthwhile1.Price (econ feasibility) 2.Technology

e. Oil Reserves - not just the amount of oil in the ground,

but rather the oil capable of being producedThis total is a function of 3 factors:

(1) amount of known oil in the ground(2) cost of and available technology(3) price of oil

4. Basic Definitions

a. Porosity - The ratio of the pore volume to the total rock volume.

b. Permeability - If the majority of the pores within a rock are interconnected, the rock is permeable. Permeability relates to the ability of a material to transmit fluids.

5. Substances Found in Reservoirs

a. Gas

Free gas is found at the highest point in the reservoir. Solution gas is that dissolved in the oil because of pressure, much like carbon dioxide in soda water.

b. Oil

Typically, the next layer beneath the gas cap.

c. Water

Likely to be a layer beneath the oil. May also be present in other areas, pulled up by capillary action. Thus, a lot of water exists all through the reservoir.

All of these substances are immobile until drilling destroys the equilibrium. Then, everything in the reservoir begins to move. It was this movement that gave rise to the first of legal issues concerning reservoirs: who owns the

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substances which are mobile?

6. Energy Sources

a. Gas - the primary energy source.

1) Gas cap expansion

Gas is the primary source of energy, provided through expansion of the gas cap that occurs when the reservoir is tapped from drilling. The drilling connects the lower pressure surface with the high pressure reservoir, and the gas cap expands, driving the gas and other substances.

2) Solution gas expansion

This process is similar to the gas bubbles in a Coke can that fizz out, bringing the syrup out with it. Here, the gas solution brings oil up and out.

To maximize the energy source you should drill as far away from the gas cap as possible because if you drill straight into the cap, the well will quickly produce the gas and drain the reservoir of its energy. The well will produce too quickly.

I.E. Drill it away from the energy source; away from the cap in a low pressure area.

Also, you may not want all that gas so quickly because it can't be easily stored; rather, it must be marketed immediately. The result is usually wasted gas and more difficult to produce viscous oil (like the syrupy Coke that is left when the fizz is gone).

Then why ever drill the upper stratum? Because surface ownership may not always be suited to drilling in the most efficient place. One solution would be to unitize the different property owners (see below). Further, the stratum of the well may not be easy to locate.

Problem: Hard to get all land owners to agree. If my land is completely away from the energy source, then

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I'll produce a ton of oil.

b. Water - Secondary energy source.

Water is compressible and seeks to expand much like the gas cap. For the maximum production you should drill up stratum, as far away from the energy source as possible. However, if you drill into the energy source down stratum, it is not as disasterous as with a gas energy source.

Q: What if the only land I own is downstructure of the reservoir?

POINT: Once you compare dynamics of the reservoir with surface ownership there are always some people better off with cap drilling.

C. Common Law Theories of Ownership and Development

1. There are two fundamental theories of ownership.

a. Ownership-in-place (Texas)

According to the ownership in place theory, the landowner owns all substances, including oil and gas, which underlie his land. Such ownership is qualified, however, in the case of oil and gas, by the operation of the Rule of Capture. If the oil and gas departs from beneath the owned land, ownership in such substances is lost.

b. Exclusive-right-to-take (Oklahoma)

Under this theory, the landowner does not own the oil and gas which underlie his land; he merely has the exclusive right to capture such substances by operations on his land. Once reduced to dominion and control, such substances become the object ownership. But, until capture, the property right is described as an exclusive right to capture.

Notice that this theory has no conflict with the Rule of Capture as does the ownership in place theory.

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The key distinction between the two is that in the ownership in place theory, the owner is viewed as having a corporeal interest (right to physical possession as opposed to a mere right to use). This distinction has ramifications in a variety of areas, most notably: ability to abandon and property taxes.

2. The Rule of Capture

This doctrine was developed to address the basic question of who owns the oil and gas extracted from a reservoir beneath two or more tracts of land.

BASIC RULE: The basic rule is that the owner of a tract of land acquires title to the oil and gas that he produces from wells drilled thereon, though it may be proved that part of such oil and gas migrated from adjoining lands. There is no liability for capturing oil and gas that drains from another's lands.

The early common law courts treated oil and gas like all other minerals. This caused a problem because the common law of minerals was designed for hard-minerals, like gold, silver, etc. Under this hard-mineral common law, the land owner owned everything above and beneath his land; the fee simple is not horizontal, but cubic. Under this common law, one would have an action for conversion against his neighbor if he could show that extraxted O&G was drained from beneath his land.

O&G is fluid. To extraxt O&G from beneath a neighbor's land, one need not physically trespass. This removed much of the force behind the old common law rule in regards to O&G extraction. Consequently, abandoned this doctrine in application to O&G and developed the Rule of Capture.

a. Analogous Bodies of Law

i. Water law

Water law supported the nonliability rule; i.e., the capturer not liable to other property owners.

ii. Ferae naturae

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Law of wild animals is that the animals are unowned until they are killed or captured.

WHY THE RULE OF CAPTURE?

b. Encouragement of oil exploration

The key factor that led to development of the Rule of Capture was the encouragement of oil exploration. We did not want injunctions allowed simply on proof of drainage. Under the old common law, measuring damages for trespass was not feasible because the technology was not advanced enough to determine amounts drained. Accordingly, an injunction would have been the only legal remedy. This would have stimied O&G development.

c. Cost of the Rule of CaptureEncouraging exploration with the Rule of Capture had some drawbacks. It encouraged self-protection. The only way a party could protect his land from drainage by his neighbor was to drill his own off-set well. This led to over-drilling.

Over-drilling leads to economic waste, surface disruption, and environmental problems. Also, the internal structure of the reservoir can be destroyed through premature dissipation of the energy source.

e.g. Spindletop

For this reason, you have much regulation of drilling and development activities - perhaps the biggest limitation placed on the Rule of Capture.

ISSUES WITH THE RULE OF CAPTURE

Note: Logically you would think two adjacent land owners would cooperate and share the benfits of production.

Q: What was reason for its extraordianary viability as a judicial doctrine? (on its face it sanctions theft)

1. Gives incentive to produce2. Accountng otherwise would be difficult.

3. Limits on the Rule of Capture

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Several judicial and legislative limits on the Rule of Capture emerged in a piecemeal fashion to address specific concerns.

a. No deviated (horizontal) drilling

The first judicial restraint on the Rule of Capture was the rule that the driller had to have the well bottomed on his own land. The incentive for deviated drilling resulted from the formation of the reservoirs and the desire to use the energy source efficiently. However, the ideal drilling location was not always available on one's own land.

b. Safety concerns

People's Gas Co. v. Tyner (1892) (p. 11) -- P was trying to enjoin D from producing a well which was going to be shot with nitroglycerin to increase permeability. P conceded that the Rule of Capture applied; his complaint was (1) that what D planned to do would exacerbate the natural drainage, to create more than natural drainage, and (2) this method was very dangerous in an urban area. D argued that the well was not very permeable, and he needed to shoot the well to increase permeability.

The court refused to buy P's first argument, and held that artificially inducing more flow in the well is consistent with the Rule of Capture because, after all, the well is an artificial intrusion itself. However, the court was convinced by P's second argument; namely, that the process was too dangerous for an urban area. Thus arose the second judicial restraint on the Rule of Capture - you can't endanger lives in order to produce O&G.

c. Ownership of Extracted Oil and Gas

Chaplain Exploration (OIL)Facts: Refinery leaked. Dug trenches to collect their oil. Neighbor dug trenches to collect it as well.

P: He owned mineral rights below-property is back in ground-mine

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Ct: No, once produced oil becomes personal property.(lost only by abandonment)

CommentaryYou can not rely on the Rule of Capture to produce gas which has already beed reduced to possession by another party. See more below.

d. Regulation

Legislative regulation of drilling and production imposes perhaps the biggest limitation on the Rule of Capture. See more below.

e. Correlative rights

You can not deny your neighbor his right to produce his fair share in the name of the Rule of Capture. See more below.

An example of this would be the use of enhanced recovery methods. You can not rely on the Rule of Capture to avoid liability for damage to a neighbors well caused by enhanced recovery like waterflooding. This, however, is largely moot. Most states except Texas have forced unitization. See more below.

4. Ownership of Extracted Oil and Gas

Texas Amercian Energy Corp.Facts:Bank wanted security interest. Main asset is natural gas were buying. UCC lien on personal prop or mortage?

Ct: Lien on prop. Not once more part of reality.

Lone Star Gas Co. v. Murchison (1962). Here, Lone Star was taking recovered gas and injecting it back into the depleted reservoir, because the reservoir was the best storage facility. P needed the storage facility in order to be able to supply to its customers in times of peak demands. It is hazardous to store on the surface. The problem here was that P failed to buy up all the rights from all of the surface owners. D owned land over the reservoir and drilled a well, producing P's gas. P sued for an injunction.

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D defended on the wild animals analogy: If one catches a wild animal and then turns it loose in its native habitat, then the animal is once again unowned. D claimed that since P released the gas back into its natural habitat, then the gas was free and available to D under the Rule of Capture.

Instead, the court held that once reduced to dominion and controlled, the gas was personal property and Lone Star would have had to abandoned the gas. To abandon the gas, two elements would have to have been satisfied:

(1) Loss of control, (2) intent to relinquish title.

Certainly, Lone Star had no intent to relinquish title here, and at least had some control.

a. Policy arguments

We need storage facilities. Deciding this case the other way would frustrate this policy.

b. Murchison's remedies

Could try to sue for trespass; or, could sue for damages as a measure of storage rights.

c. From whom to obtain storage rights?

Storage of natural gas is not an insignificant problem. The gas company may have a difficult time determining from whom to obtain the storage rights - the surface owner or the mineral owner? Often these are not the same person.

i. Non-ownership states (Oklahoma)

In states that do not follow Texas' ownership in place theory, then you should buy from the mineral owner.

ii. Ownership in place (Texas)

In states like Texas, then the minerals owner doesn't own anything in this situation, because the reservoir has been depleted. Then, the gas

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company should buy storage rights from the surface owner.

The best or safest path would be to pay both parties.

5. Conduct Permitted in Extraction - Correlative Rights

The correlative rights doctrine provides that each owner of oil and gas in a common reservoir has the right to a fair chance to produce the reservoir substantially in proportion to the quantity of recoverable oil and gas under his land compared to the quantity in the entire reservoir.

The correlative rights doctrine is a corollary to the rule of capture. Since the Rule of Capture was adopted to benefit the public interest by encouraging the development of oil and gas resources, activity inconsistent with that purpose is not protected by the Rule of Capture. Accordingly, the doctrine of correlative rights provides that waste or wasteful production techniques will bring liability, as will negligent damage to the producing formation to the detriment of others.

There are essentially three main duties of a producer under the correlative rights doctrine.

a. Duty not to engage in unlawful production

"Fair Share" concept - Wronski v. Sun Oil Co. involved a violation of a state regulatory order in Michigan. This order permitted only 1 well per 20-acre tract and limited production to a maximum of 75 bpd.

Sun Oil had drilled in accordance with the spacing order, but was over-producing by an alleged 150,000 bpd. The neighbors sued Sun Oil, claiming that Sun was draining additional oil from their land. Suit was for conversin of their oil.

1. Rule of Capture not applicable

Q: Why isn't sun protected by the rule of capture?

One reason is to protect A and B, to make sure they get their fair share of oil in the ground.

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Sun was only producing from its land and the Rule of Capture would seem to justify it taking whatever it could. But, for the Rule to be fair, the corollary of self-help is necessary; i.e., neighbors must be able to drill offset wells. The Regulatory Order here made self-help impossible. Thus, P won the case.

This case illustrates how state regulation is a limit on the Rule of Capture.

*Regulation eliminates self help alternaitvea. Can't protect yourself from violations of regualtios by violating them.

2. Referenes to the "Fair Share Doctrine"

-Once a state agency starts regulating oil and gas production, they should do so in a way that each land owner can produce his fair shar of the o & g beneath the land.

All landowners overlying a common reservoir have an opportunity to obtain their "fair share" from the reservoir, and when a driller acts so that others cannot protect themselves, they are denied their fair share, and the Rule of Capture will not apply.

a) Recoverable reserves

The owners are only entitled to recover their fair share of recoverable reserves; volume is not the key here. For example, landowners overlying relatively impermeable strata are not entitled to the same volume as owners overlying more permeable strata. Other considerations:

*Just an opportunity to get fair share of recoverablereserves, doesn't ensure it.

i. Recoverable when? The best answer is that if a landowner delays drilling, he is not entitled to make up what he has lost.

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ii. What about regulation? Do we look at how a landowner could drill or must drill under the regulation.

Thus, "fair share" is a slippery concept, and it is difficult to attack a regulatory order on this ground.

b. Duty not to waste or unreasonably injure the reservoir

Elliff v. Texon Drilling Co. (1948) -- This case established that a landowner is liable in negligence for destruction of O&G in a reservoir even though the destruction takes place entirely on his own property.

This case involved a blow-out. D had drilled improperly, failing to use drilling mud so as to lubricate the drill bit, help wash particles of rock back to the surface, and keep pockets of high pressure fluids sealed off. The drilling mud was too light, and as a result, the pockets exploded. P sued, claiming that O&G was sucked from beneath his property through D's blown out well. D tried to defend on grounds of the Rule of Capture.

The court held that the Rule of Capture is not a shield for negligently wasting a neighbor's oil and gas. The purpose of the Rule of Capture - to increase oil production - is not furthered by allowing its application in this manner. Accordingly, the correlative rights doctrine requires due care and D is liable for waste of P's gas. Where the actual burning occurs is immaterial.

c. Duty to plug abandoned wells.

Problem w/ ROC: Encourages reservoir destruction-surface waste-econ waste (more $ spent on drilling)-premature abandonmnet of wells

i.e. 5 wels at 5bpd shut down;1 well at 25bpd keeps a pumpin' i.e. Underground Waste of Oil.Premature abandonment often leads to contaminated water supplies & other environmental problems (therefore,

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govt. requires an abandoned well to be plugged w/i a certain period of time).

6. Kinds of Oil and Gas Interests

a. Fee interest

Ownership of both the surface and the minerals rights in fee simple absolute. The "whole bundle of sticks" of rights in real property.

b. Mineral interest

It has become common in the U.S. for mineral rights to be severed from the surface rights in land. The mineral interest in O&G is the right to search for, develop and produce O&G from the described premises and, in states that have adopted the ownership in place theory like Texas, the present right to possess the O&G in place under the property. Aspects of a mineral interest fall into three classes:

1. Easement for surface use

Mineral interest owner has the right to use the surface of the land under which he owns the minerals to search for, develop and produce the minerals. The mineral estate is the dominant estate, subject to the accomodation doctrine discussed later.

2. Right to lease or sell the mineral interest

The mineral interest owner has the right to explore for or develop O&G on the property in which he owns the mineral interest; he can also transfer that right. The right to lease is referred to as the executive right.

3. Right to benefits under an O&G lease

The mineral interest owner has the right to whatever benefits are provided to the lessor under the terms of a lease that transfers the right to develop.

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c. Leasehold interest - "operating" or "working" interest

This is the right to the mineral interest granted by an O&G lease. The lessor typically retains a possibility of reverter of the mineral rights, and a royalty interest in production.

d. Surface interest

This is what is left of the bundle of rights of ownership in land after the mineral interest has been severed. These rights are residual to the mineral rights; whatever is not included in the mineral rights the surface owner has.

The surface ownership is subject to the easement for developing the mineral interest. That is, it is servient to the dominant mineral interest.

e. Royalty interest

A royalty interest is a share of production free of the costs of production. They do not have the incidents of ownership of a mineral interest - i.e., no executive right, no right to develop.

1. Landowner's royalty

Retained by the lessor in the O&G lease.

2. Overriding royalty

Royalty interest carved out of the lessee's interest under an O&G lease. Frequently given as compensation to landmen, etc. It ends when the lease terminates.

3. Non-participating royalty

Royalty carved out of the mineral interest entitling its holder to the stated share of production without regard to the terms of any lease.

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Frequently retained by mineral interest owners who sell their rights.

f. Production payment

A share of production from the property, free of the costs of production, that termintates when an agreed sum has been paid.

g. Net profits interest

Expressed as a fraction or percentage of production. Similar to a royalty, but it is different in that it is payable only if there is a net profit.

h. Executive interests

Executive right is the power to lease minerals. This right is frequently severed from the other incidents of mineral ownership.

II. State Regulation of Drilling

A. Spacing and Density Rules

Initial Purpose:1.Effect Conservation-Prevent Waste2.Portect Correlative Rights.

These regulations were developed initially to limit problems caused by the Rule of Capture. The Rule of Capture encouraged people to drill and produce O&G as rapidly as possible to prevent it from being taken by their neighbor. This led to (1) violations of correlative rights and (2) to four types of waste.

- Surface waste

Too many wells occupy the surface.

- Underground waste

Too many wells drain the reservoir inefficiently, leading to its premature destruction.

- Economic waste

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Wells unnecessary to thoroughly drain the reservoir are encouraged through the self-help corollary to the Rule of Capture.

- Premature abandonment of reservoir

If the well owner cannot get enough out of the well to cover his costs, then he will abandon the well. If there were fewer drillers, the well will be produced because the drillers can recover their costs. Too many wells spread production too thin.

1. Effect of drilling permit

a. minimize danger of well blow outs

Secure installation of high-pressure valves and fittings are required.

b. Controls disposition of oil and gas

Upon completion of a well, the holder of the permit must file a well completion report.

c. Prevents underground pollution of water

Surface casing must be installed and cemented in place from the surface to below the deepest known source of potable water.

d. Requiring vertical drilling

Directional wells require the use of whipstock equipment, and the sale of such equipment is regulated by special permits; unless such a permit is granted, use of such equipment is prohibited.

Horizontal drilling was already prohibited by judicial limitations placed on the Rule of Capture. Codifying this limitation just serves as another means of limiting such practice.

2. Spacing and Density Rules

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The RRC will plat out the field's surface and allow surface owners to share in production from the well on that unit - usually on a surface area ratio basis.

a. Rule 37 Spacing

467 ft away from lease boundry1200 ft between wells on same tract.

Conserve reserves and protects correlative rights. Prevents surface waste; fewer wells will occupy the surface.

b. Rule 38 Density

How many acres must be assigned to each well. For example, oil wells typically require 40 acres, while gas wells require 160 acres. The theory behind this requirement is that this is the minimum acreage that will will lead to efficient drainage of the well. Also protects correlative rights by ensuring that only as many wells as are needed to drain a tract are drilled.

i. Drilling units

In most states, the state regulatory commission establishes drilling units for each field and specifies where on each unit the well may be placed. Only one well may be drilled on such a unit to produce from the common source of supply (unless an exception is specifically granted).

ii. Shape of units

Drilling units are usually rectangular. A well, however, drains radially in the shape of a circle. How can rectangular shapes be justified?

- Historical reasons

The shapes generally go back to how land was historically split up - 40 acre squares. If other shapes are used for drilling units, problems in ownership will be exacerbated, and there would be

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larger administrative costs in describing the plots.

- Compensatory drainage

It all evens out somehow anyway, so administrative convenience is justified.

c. Challenging regulatory orders

Once state-wide rules are set, some property owners may want to argue that a particular rule does not work best for their fields; i.e., that the drilling unit should be smaller, or drawn differently. Once field-wide rules are in place, however, challenging them is not easy.

i. Improper Spacing Based on Facts

There is a presumption that the regulatory agency has acted correctly. This is known as the "Substantial Evidence Rule". If any evidence exists that the agency has acted correctly in developing spacing rules, then a court will not overturn its decision.

The agency's discretion includes a balancing of different factors. A lot of things might constitute waste, so the agency ends up with an enormous amount of discretion in establishing rules to end waste.

See; Calvert Drilling Co. v. Corp. Commission (OK 1979). The court faced a claim that a spacing unit covered portions of a formation that were not productive of oil and gas. The court found a that the plaintiffs failed to conclusively show that that the land in question did not hve oil beneath it. It sustained the spacing unit despite the commission having very little evidence to show that the land did have oil beneath it. The Commission's regulations were upheld based on the "substantial evidence" rule.

ii. Incorrect Application of Law

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Another way to challenge field-wide spacing rules is to show that the regulatory agency failed to consider something it is required to by law. For example, to justify field rules based on prevention of waste, it must be shown that waste will occur without spacing. If the agency fails to do so, they have not applied the law properly.

iii. Order Issue

Argue that the standard employed by the agency is capricious and arbitrary resulting in the loss of property rights.

iv. Specific Statutory Provisions

Many statutes provide for a specific system to be followed. If this mandate was not followed explicitly, then the agencys order should lack legal effect.

d. Geological exception to spacing and density requirements

In many states there are geological variations among fields such as porosity, permeability, etc. When this issue is raised, a hearing is held to determine whether special field-wide rules should be established.

3. Rule 37 exception to prevent waste

Sometimes exceptions even to special field-wide rules are necessary to take into account variations within the field itself, such as geological variations, or variations in ownership.To obtain such an exception, the claimant must make a special appeal to the Commission, which then holds a hearing; others affected by the ruling must be notified. The argument made for these exceptions is that unless a well is drilled in an exceptional location, waste will result. Underground conditions such as sand thickness, saturation, porosity, etc. can dictate drilling locations that may be other than permissible locations.

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a. Reservoir waste

Clearly reservoir waste can be a reason for granting an exception. If it can be shown that the proposed well will result in more efficient drilling from the standpoint that more oil can be recovered or less energy can be dissipated, an exception will be granted.

Q: To what extent can RRC take econ issues into account?

b. Economic waste

In most states, economic waste can also be considered in granting a rule 37 exception. But, this is not carried to an extreme. Savings on drilling equipment will probably not, by itself, justify an exception.

One instance where a rule 37 exception to prevent waste was granted based on economic waste was in Exxon Corp. v. Railroad Commission. The drilling situation was as shown below:

BTA1 BTA2

Exxon

Devonian Field

Montoya Field

Ellenberger Field

BTA's two wells were drilled close together but satisfied the 1200 foot restriction because they were bottomed more than 1200 feet apart. The problem occurred when BTA wanted to plug well 2 up to the Devonian Field. It was entitled to the second well because it had enough acreage, but the spacing rule would be violated.

BTA argues that #1 is doing a poor job, but it would

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cost more to drill a new well than its worth.*Either give us permission to shorten our existing well or we won't drill. Basically, we'll be producing oil that otherwise won't be produced.

Exxon claimed that waste exceptions can only be granted when reservoir waste is shown, not purely on economic waste. Also, they claimed there would be an incentive to drill in bad faith in improper locations knowing you could then get an exception based on economic waste.

The Tx. S.Ct. upheld the the exception. This suggests that there are instances when the Commission may properly consider economic waste. Significantly, however, there was no finding of bad faith on the part of BTA.

OPEN QUESTION: How would RRC rule if you eliminated half of BTA's argument?

1. Phys waste of oil2. Only way is to use and existing well

Sclocker Case: Only second half of arg. Drilled deep, econ waste was only arg . Lost.

Prof: Read Exxon as requiring showing that some oil could be left in the ground.

4. Rule 37 exception to prevent confiscation

Often times the owner of a small tract of land will not phsically be able to meet either spacing or density requirements. In such a situation, the landowner might seek a voluntary pooling agreement with neighbors; but, these are hard to negotiate. In most states this is remedied by a forced pooling statute. Texas, however, had no such statute until 1965.

In Texas, where oil beneath one's land is owned in fee simple absolute, to prevent the oil from being taken by neighboring wells the small tract owner is entitled to a drilling exception to prevent confiscation. As a general rule, every tract that does not amount to a "voluntary subdivision" is entitled to at least one well to prevent confiscation. The fact that the owner turned down an

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opportunity to pool with a larger tract will not deprive him of this exception.

*If agency says I can't drill, its confiscating my fee in OG by denying access. Or letting someone take it away from me.

a. The voluntary subdivision rule

The voluntary subdivision rule is an exception to the exception to prevent confiscation. It provides that an exception to prevent confiscation will not be granted to protect tracts which were (1) voluntarily subdivided after a field-wide spacing rule has attached, or (2) subdivided in contemplation of O&G production, regardless of when the owner acquired the land (i.e. after a lease has been executed). Notice that an oil company leasing a small tract can not get a permit because at the time they lease they are contemplating drilling.

The date of attachment of spacing rules is the date of discovery of oil and gas in a continuous reservoir regardless of the subsequent lateral extensions of such reservoir. For a multiple reservoir structure, the date of attachment for the multiple reservoir fields separated vertically shall be the same date as that assigned to the earliest discovery well for the multiple structure.

HYPOTHETICALS:20 acres, need 40.A tries a r. 37 exception. Other owners in the filed have to be given notice.

1) Vol Sub: A has land, knows its in part of field, then subdivides.

a. subdivided when O&G development was reasonably probable

2. So if you had 40 and sold half, youre stuck w/out a permit

OPTIONS1.Jointly develop two tracts of land2.Get forced pooling3.Century Doctrine

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b. The Century doctrine

This doctrine provides that a well permit should be granted even to a voluntary subdivision if a well could have been drilled on the original pre-subdivided tract. If so, the well permit should be granted even though only the owner of a small subdivided tract applies for the permit in the face of opposition by the owners of the remaining portion of the subdivision.

HYPOTHETICAL80 original plot70-A10-B: Yes B's acres are in a voluntary subdivision (already

subject to spacing rules) but if you ignored purchase, it was entitled to two wells

If both the grantor and the grantee apply for a permit based on this doctrine, the Commission should grant the permit to the applicant with the best location; i.e., to the applicant whose lot best conforms to the field rules and/or will produce the least amount of waste.

The loser in such a joint application contest does not get to share in the production of the well. She will be faced with a party arguing the Rule of Capture. However, the Rule of Capture does not make sense here because it only makes sense in conjunction with the corollary of self-help, which is now impossible because of the spacing regulations.

In Ryan Consolidated Petroleum Corp. v. Pickens, there was a voluntary subdivision. 4/10 of an acre lot was created before oil discovered in the area, lot was entitled to one well under the exception to prevent confiscation. Both owners of the subdivided tracts applied for a permit. The Commission gave it to the party best able to drill efficiently. Forced pooling was not ordered. The dissent (Smith agrees) argued that the Rule of Capture makes no sense without self-help; instead, an equitable accounting should be ordered. The only bright side to this opinion is that it encourages voluntary pooling.

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Today, forced pooling can alleviate some of the hardships. In addition, the parties may agree to voluntary pooling rather than battle it out for a permit. This allows some sharing of the costs.

c. Examples

1. At a time when there is no drilling or development for oil and gas in the vicinity, the owner of an 80-acre farm conveys a half-acre lot to Able. Several years later, oil is discovered in the vicinity, and Able applies for a Rule 37 exception. Able entitled to the exception because the subdivision, though voluntary, was before attachment of the voluntary subdivision rule.

2. A new discovery well has been completed four miles out of town. J owns a large tract of land outside of town. He sells all of it except for a small corner lot where he plans to build a Dairy Queen. Additional drilling reveals that the reservoir extends under the lot J retained.

Even though J has not knowingly tried to evade the spacing rules, the Commission disregards questions of intent and no exception will be granted. An owner is put on constructive notice once there is a discovery well into the field underneath ones land.

J can still try to appeal to equity to get his exception.

3. G owns a 250 acre ranch. She leases 10 acres to Oil Co. to drill a well. Oil Co. will not get a permit because this is definitely a voluntary subdivision - the whole purpose was to drill. Thus, the voluntary subdivision rule applies to leases as well as to fee conveyances.

4. 80 tract of O.(1990) no oil. A buys half acre. Two years later Oil found-A gets permit.

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Sect 1 r. 37 sounds like he shouldn't. *Section 2 is applicable rule. Not vol sub unless sale came after spacing rules "attached to that piece of land".-i.e. When O is discovered in the vicinity.

d. Merger doctrine

The owner of a small tract may lose the right to drill in an exceptional location through the merger of the small tract with another tract. Or, alternatively, if a small tract owner buys two adjacent small tracts that would all be entitled to an exception, he cannot get 2 more permits. When tracts are joined under common ownership, their drilling rights are merged.

e. Why would anyone want to drill on a small tract?

Depending on the rules for creating the well allowable, it may still be profitable. Under the old RRC rules, the well allowable was based half on surface acreage and half on the presence of a well. Thus, a well on a 1 acre tract would be allowed to produce over half of what a 40 acre tract would be allowed. This obviously resulted in the 1 acre tract well draining from the other tracts.

B. State Regulation of Production

Spacing and density requirements protect correlative rights and prevent waste. Most O&G states, however, concluded that these regulations were not enough. The amount of production from the wells could also have a bearing on production.Well Allowable Regulation-Ideal Process

1. Basic 40 unit-100bbls/daya.surface/acre formula assumes uniform underground geology.

2.After a field is discovered-REexamine-is this proper for this field

3.Is this most effecint way-To Prevent Waste.

4.Look at individual wells.

No state allows "open flow" production for the simple reason that

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such production would lead to reservoir energy waste and the loss of production. Excessively fast production of oil generally shortens the life of the reservoir because too much of the energy source may be produced, making underlying oil unrecoverable. Some gas wells do produce most efficiently at full clip, however. In the following discussion, oil wells are assumed.

1. Maximum Efficient Rate (MER)

To assure maximum recovery of oil, well production may be restricted to a maximum efficent rate of recovery. MER is the designation for the maximum rate at which a well can produce without impairing the efficiency of the reservoir drive with consequent physical, underground waste.

MER is the upper limit of production beyond which any increase will mean a decrease in the amount of oil ultimately recoverable. It may be that after development in a field the production of 100 bpd from a number of wells is beyond the MER of the field, and so the well allowables will be reduced to protect against waste.

No one challenges the concept of MER. It is an accepted function of state regulation. Litigation arises, however, once MER is established for a field and must be allocated to various wells. The question becomes one of allocation to wells so as to protect correlative rights.

2. Market Demand

The system of proration to market demand was spawned by the discovery of oil in Texas in the 1920's. Suddenly, large reservoirs came on line, flooding the market and driving prices down. As a result, the producers either shut down the well, or produced even more to make enough money.

Several States created the Oil States Advisory Committee, which eventually came up with a plan to restrict statewide production to reasonable market demand. This plan was implemented with legislation, which was found to be constitutional.

Under the plan, production in excess of market demand constituted waste. The participating states determined overall demand, and then allocated it to each state. The

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individual states then allocate the state's allocation to the individual wells.

The system itself required a lot of regulation:

a. Must determine the total demand for each state.

b. Must allocate among each reservoir in the state.

c. Must allocate reservoir demand among each well on the reservoir.

The system lasted about 35 years, until the market for oil became global. At that point, the system fell apart because the states could no longer control the price of oil.

3. The "Yardstick"

In Texas, oil production is regulated based on the allowable yardstick. The yardstick is simply an administrative convenience. It bears no relationship to the MER. The production limit for a given well is based on its depth and the size of its production unit. The larger the unit or the deeper the well, the higher the yardstick.

Allowables based on how deep well is and the size of the unit.

Reason to Regulate Production 1. to protect correlative rights. 2. to prevent damage to a reservoirs pressure3. to encourage deep drilling.

a. Exceptions

You may have special field-wide rules established by the Commission if necessary to prevent unfair treatment.

b. Interplay with MER and Prorationing to Market Forces

When market demand factors come into play, the yardstick is reduced on a pro-rata basis for each well in the state. For example, if Texas' market demand factor is 50% and a well has a yardstick of 1000 bpd,

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then the production for the well will be limited to 500 bpd. Today, since market demand is 100%, you do not see this. However, you might still find a well whose MER is less than the yardstick. In such a case, the MER controls.

4. Field Allocation - the problem of small tracts

The main problem with well allowables is illustrated when there are small tracts in the field ("small tract" being one that had to obtain a Rule 37 exception for a drilling permit). The yardstick, based on depth, pre-supposes that the well has assigned to it the unit acreage for the field. By definition, a small tract does not. Allowing the small tract owner to produce based on the well allowable would clearly violate the surrounding tract owners correlative rights. Accordingly, the allowable must be reduced.

ReM: Allocation is based on spacing unit applicable to the field not to the number of acres actually assigned to the well.

If a formula for allocating the allowable to a small tract were based strictly on surface acreage, production from small tracts could be economically infeasible. The prospect of drilling at a profit is necessary to make the Rule 37 exception workable. If we cut it down proportionally no one will drill on the tracts.

In answer to this, prior to 1961 the Commission based many well allocations on the 50-50 formula - 50% allocation based on acreage, and 50% based on number of wells in the field. This system, however, largely favors small tract owners.

HYPOTHETICAL-50/50 RULE160 acre filed-5 wellTotal allowable is 1600/dayTake 1600/ half it 800/80050% on surface acreage-800 divided by 160=5 barrels/well50% on well amount-800 divided by 5=160 per/well40 acres=200+160=3601acre=5+160=165

a. Judicial History

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1. Railroad Comm'n v. Humble Oil (Tx. 1946)

The Commission took the position very early that each small tract entitled to at least one well as a matter of right should also be entitled to drill at a profit. Thus, a formula that favors small tracts is justified, especially once the Rule of Capture is considered. The 50-50 rule was upheld here against a challenge by a holder of a large tract.

2. Atlantic Refining v. RR Comm'n (Tx 1961)

This policy favoring small tracts was reversed in this case which involved a gas field with its allocation based 1/3 on the well count and 2/3 on surface acreage. Under this formula, a well sitting on 3/10 acre with a Rule 37 exception would produce $2.5 million worth of gas over its life, while the value of the gas originally in place beneath the tract was only $7000. In light of this evidence, the Tx. S.Ct. stated that the formula denied large tract owners their fair share: an arbitrary and capricious use of the formula.

RULE: Confiscatory-can't base formulas on what would make it profitable to drill on small tracts.

3. Halbouty v. RR Comm'n (TX 1962)

Broadened Atlantic. The Tx. S.Ct. came close to suggesting that the 33-66 and the 50-50 formulas were invalid per se. These formulas were discriminatory against large tract owners who were being denied their fair share.

It was later decided that this decision would not be applied retroactively. Thus, where producers had spent much money developing small lots, the allocation formulas for the reservoir would not be overturned.

b. New Formulas

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Since these decisions, some formulas have split - 50% allocated based on surface acreage and 50% allocated based on acre feet of oil under the surface, the latter factor depended on the thickness of the stratum.

However, today new formulas are largely unneccessary because Texas has enacted forced pooling largely in response to these decisions.

Why does Texas have peculiar rules protecting small tracts creating a disincentive to pool?

- TX has a large number of small independents and thus are a large part of the Texas energy industry- East Texas Field: a very large reservoir controlled

entirely by independents- RRC is elected

But see Pickens CaseB/c diff in thickness of reservoir, straight surface-acre fromula was unfair.-RRC rules based on who will get flooded out first are acceptable.

5. Gas-oil and water-oil ratios

In addition to simply assessing allowables based on the yardstick or the MER, the Commission may regulate a wells production based on other considerations (such as discovery wells, stripper wells, etc). There may also be an adjustment based on gas-oil or water-oil ratios.

For example, suppose you have a gas cap expansion reservoir. The Commission might regulate based on the amount of gas produced along with the oil in order to maintain the reservoirs pressure.

Suppose each well in the reservoir is allowed 100 bpd, and 2000 cu ft of gas is needed to produce 1 barrel. Since this is a gas cap expansion reservoir, some wells will produce more than 2 Mcf in bringing up a barrel of oil, depending on where the oil is. This may be wasteful. In reservoirs like this, the Commission may impose a gas-oil ratio.

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The per day well allowable for oil is 100 bbl, which can be produced without waste if 2 Mcf come up with the oil. In order to prevent gas waste, however, limit the production to either 100 bbl of oil, or 2 Mcf of gas, whichever comes first. Clearly, this favors the down structure wells, which can produce their oil allowable without being concerned about too much gas; the up structure wells, located near or on the gas cap, which will produce gas rapidly and not reach the oil allowable. This seems to be a clear violation of correlative rights.

a. Denver Producing & Refining Co. v. State (OK 1947)

Facts: Lessee of land over cap argues that 2:1 ration failed to protect correlative rights-had to produce more slowly than the others to protect drainage.

The S.Ct. held that in this sort of conflict between conservation of natural resources and protection of correlative rights, conservation wins. The Commission may prevent waste even to the detriment of correlative rights.As an alternative to this harsh result, in Texas the Commission will allow you reinject the natural gas to preserve the energy source. By doing so, you get a bonus allowable based on how much gas is reinjected.

b. Water drive reservoirs

Similar rules apply to water drive reservoirs. The state regulatory agency may impose rules that limit the water-oil ratio. There, the down structure owners will be the ones to suffer.

6. Gas Prorationing

Gas prorationing is much more complex than oil. Although many of the same factors are considered - such as market demand, preventing waste, and correlative rights - gas prorationing statutes are more detailed than their oil counterparts.

C. Regulation of Enhanced Recovery Operations

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Once a reservoir's natural energy source is exhausted, enhanced (secondary) recovery techniques may be employed to continue production.

1. Types of Enhanced Recovery

Enhanced recovery operations can be divided into two different types - secondary and tertiary methods.

a. Secondary Methods

There are two secondary methods which have been conventionally used because they are relatively inexpensive. They are gas injection and waterflooding.

i. Gas Injection

This simply refers to reinjecting gas back into the reservoir to maintain the pressure in a gas drive reservoir.

ii. Waterflooding

Similarly, water flooding refers to pumping water into a reservoir to drive the lighter oil to the wells. Comes up thru output wells.

b. Tertiary Methods

Tertiary methods are much more expensive than the conventional secondary methods. There are three main types.

i. Thermal

A thermal recovery method refers to a situation where the oil is heated by the injection of steam or fire to increase the oil's flow.

(1) fire flooding - inject oxygen into the reservoir and set it on fire; problem is that it is difficult to control(2) steam injection - inject steam through my well into the reservoir, then pump out the water (cooled steam) & the oil; repeat

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ii. Miscible

A miscible recovery method refers to a situation where a fluid is mixed with the oil to increase its flow. A common fluid used is carbon dioxide.

iii. Chemical

A chemical recovery method refers to the situation where a detergent is injected into the reservoir to allow the oil to flow more easily by breaking the surface tension b/w the oil and the rock grains.

All enhanced recovery methods change the mechanics of a reservoir. Accordingly, normal regulation rules do not effectively protect correlative rights or prevent waste. Once enhanced recovery is begun, it no longer makes sense to pursue production on a well by well basis. It is most efficient to treat the reservoir as one producing unit. This process is known as unitization.

2. Unitization

An overall agreement to produce an entire reservoir. It is not the same thing as pooling which refers to the combining of individual tracts to form a rule 38 density unit.

All tracts are assigned to unit-all get benefit of production, regardless if well is on your land.

Unitization can be voluntary or compulsory. Under voluntary unitization, all of the various owners of interests in a reservoir agree to a joint operation to enhance recovery. Unanimous consent of all owners is difficult to obtain b/c:

(a) some owners will hold out for a better deal(b) some wells are still profitable and the owners of these see no advantage in unitization,(c) small independents w/ profitable wells dont want to lose their cash flow and sink in more capital (d) high transactional costs(e) difficulties in creating a plan: expenses & profits

Accordingly, compulsory unitization laws have been passed in most states. Rarely happens during primary recovery phase. Texas, however, has no such law.

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a. Forced Unitization

Under a forced unitization act, the conservation commission can compel parties to unitize their production efforts. It is, however, a lengthy process as the following illustrates.

i. Approval

All statutes requires some ratio of approval by interested parties. For example, in Oklahoma 63% of the mineral owners must voluntarily agree to the plan. In Mississippi it is 85%.

ii. Unitization Plan

The parties must put together a unitization plan. Typically, the plan must address a variety of issues such as: the sharing of costs, identifying the operator, sharing of production, etc...

Invariably, the operator named is a large oil company because small companies do not have the resources to engage in an expensive operation. This in essence squeezes small operators out of the market for a unitized fields. For this reason, the abundance of small operators in Texas are responsible for Texas not having a compulsory unitization statute.

iii. Approval

The regulatory commission must approve the plan at a hearing in which all interested parties can be heard. This is typically true even for voluntary unitization plans - approval must be obtained.

b. Unitization in Texas

Texas has no compulsory unitization statute. All unitization must be voluntary. However, the state can effectively force unitization by other means. For example, they can prohibit the flaring of gas where gas injection is needed, cut back on gas to oil ratios, or

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lower allowables for non-unitized fields.

c. Liability to Non-participating Interests in Texas

Since unitization is not compulsory in Texas, a non-participating party might claim damage when the mechanics of the reservoir is altered by enhanced recovery techniques.

In Baumgartner v. Gulf Oil Corp. (Neb 1969) the issue was what liability might the Oil company have if the water from a flooding operation encroached beneath the land of the non-participant and drowned out his potential wells?

Everyone but P decided to participate in the secondary recovery operation. P was invited, but he declined. The Oil Company got state approval for unitization.

P applied to the Commission for his own drilling permit. However, by the time he drilled it was too late - the oil was flooded from beneath his land. P sued the operators of the unitized group claiming deliberate and willful trespass. P claimed D was liable for the gross value of the oil which was pushed from beneath his land, without a deduction for the cost of drilling.

The S.Ct. took the position that P was only entitled to protection of his correlative rights - to an opportunity to access his fair share which he could have received by participating in the plan. P gave up his fair share by rejecting the plan.

Theories of recovery which are available to a plaintiff whose fair share is taken away by an enhanced recovery method of production are as follows.

i. Trespass

Baumgartner illustrates the difficulty in getting damages for trespass from secondary recovery operations. Such an approach is typically rejected by courts. If the law were otherwise, enhanced recovery methods would be halted because

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everyone would hold out knowing he would be compensated in the end. Accordingly, this is an approach rarely pursued by plaintiffs.

Q: What if no offer to come in. What if p could make a reasonable profit w/out water flooding?

ii. The negative Rule of Capture defense

The Texas Supreme Court in the Manziel case suggested that if a driller can pull oil from beneath his neighbor's land, he should be able to push oil from beneath that land.

This is fairly logical. But, the problem is that it shifts the balance of power. If the oil company knows it will never be liable, then it has no incentives to unitize. This approach has largely been abandoned and courts generally will not allow a party to sweep oil from beneath a neighbor's land using enhanced recovery under the shield of the Rule of Capture.

iii. Nuissance

Q: What are the relative benfits of act to defendant and public compared to the relative harm to the P?

What the courts are applying to this type of situation now is similar to a nuisance analysis - weighing various factors.

- Time, location of D's conduct- Public benefit, i.e. conservation- Benefit to D, Harm to P- P's ability to prevent the harm.

Perhaps the most important factor considered, however, is prior commission approval. Since all plans must be approved by the commission, there is a strong presumption that they are not a nuissance.

In Baumgartner, the unitized group had plan approval. This was a strong factor in their

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favor. Additionally, they had given the plaintiff the option to join he group and he declined. This factor seemed to weigh heavily in the court's nuisance evaluation.

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Problem Number 1:Suppose a regulatory agency approves a voluntary unitization

plan. What sort of remedy does a landowner have if his land is not part of the unitization?

- Xs field has produced for 13 years.- The field is just about through w/ primary production.- Most landowners agreed to a water flooding plan.- Regulatory agency held a hearing and forced unitization.- X owns 500 acres just outside the field as defined by theregulatory agency.- X was offered $50 a year in the agreement.- Xs expert testifies that the field goes under Xs land, which had $1,000,000 worth of oil and $950,000 of it has been pushed out. - X is awarded $950,000 in compensatory and $5,000,000 in punitives for the trespass

Xs position:Y trespassed by pushing the oil out from under my land, and

it was in bad faith.

Ys position:(1) estoppel - X could have showed his belief as to the oil

beneath his land at the agency hearing but failed to do so.(a) X failed to exhaust his administrative remedies(b) collateral estoppel - X acquiesced to the shape/geology of the field and cannot collaterally attack that finding

(2) Statute of Limitations - (3) Policy

If we allow X to show up years later and collect $6,000,000, then secondary recovery will be greatly discouraged leading to waste of natural resources.

(4) Improper measure of damages (a) X should only be due the profit from the $950,000 worth of oil not $950,000. The trial court failed to deduct the expenses in recovering the oil. (b) No bad faith was present as no one thought that the land had so much oil. Thus, no punitives.

(5) No trespass(a) authorized by the agency(b) Negative Rule of Capture

- whether pulling or pushing oil, pressure differential is created in the reservoir. Thus, if one is not liable for pulling oil (drainage), one should not be liable for pushing oil via

secondary recovery. (6) Administrative Law Doctrine

(a) deference to the agency should be granted- substantial evidence is needed to overcome theagencys findings

(b) primary jurisdiction is w/i the administrative agency

- X should have to go to the agency and provide itw/ new evidence & findings

Xs possible tort theories:(1)conversion - if in a state adhering to the ownership

theory(2)nuisance (Baumgartner)- balance the interests

- look at fairness, notice- benefit of unitization- authorization by the agency- burden to X

Xs responses to Ys arguments:(1) Estoppel

- not well-educated, not rich, cant afford experts forthe administrative hearings, can only get a contingentfee lawyer to protect his interest

- But who cant make this argument? What would beleft of the administrative process and rules?

(2) Statute of Limitations- Waterflood program began 4 years ago; 2 year limitations. - a continuing trespass- maybe, discovery rule helps- TX court has recently held tha RR com records are notinherently undiscoverable to a lessor.

(3) Policy- The statute doesnt authorize injecting of water into strata under land not in the unit.

(4) Measure of damages- The Court must say as a matter of law that following an administrative ruling is good faith in order for there to be no punitives and overturn the jurys finding of fact.

(5) Trespass(a) not authorized to inject water into strate under

land not in the unit(b) Negative Rule of Capture

- no self-help remedy as impossible in an enhancedrecovery situation- would allow a party who owns most of a reservoir to flood out everyone else

Environmental Regulation

FEDERAL LAWS

Map of the oil & gas industry:acquisionexplorationproductiontransportation/storagerefining

Acquisition, exploration, and production are upstream activities. Transporation, storage, and refining are downstream activities.

The laws mostly affect downstream activities.

4 main laws:(1) Clean Air Act - intended to reduce air pollution through EPA regulations; one way is to state what types of pollutants can be released into the air; wells producing less that 10 barrels per day are exempt (thus most wells in the U.S. are expempt from this statute); pollution is measured by the well not by the field, therefore, not applicable to exploration and production; but very important to refining and manufacturing

(2) Clean Water Act - intended to maintain the nations wate supply; requires a spill-prevention plan, a plan to remediate a spill (a clean-up plan), an Army Corp. of Engineers permit to drill in a wetland (not to be confused w/ the Aggie Corp. which provides permits to drill sheep), a general discharge permit in order to discharge pollutants/fluids.

The general discharge permit requirement is expempted:(1) for wells producing less than 10 bpd,(2) injection wells are exempted (but still may be subject to state water laws).

(3) RCRA/Resource Conservation & Recovery Act - A cradle to grave system for hazardous wastes; a waste is hazardos if listed in RCRA or characterized as having hazardous properties.

Not important to exploration and production:(a) exploration and production wastes are exempted; and(b) RCRA applies mostly to undergound storgae

(e.g. the local gas stations tanks)

(4) CERCLA - designed to create a mechanism for cleaning up a contaminated site; exploration and production are exempted here as well, but some drilling mud is subject to CERCLA; it does impact acquisition as purchasing land subject to CERCLA/Superfund can subject one to liability under CERCLA; to overcome this companies get an environmental survey (essentially environmental

due diligence).

Other statutes can have an impact on exploration and production:(1) Endangered Species Act -

(a) prohibits federal action that may endanger speciessurvival;(b) prohibits trade of an endangered species or its parts;(c) prohibits the taking of an endangered species w/ taking defined as capturing, killing, harassing, or harming w/ harm having a broad defn including modification of the habitat - important to exploration and production

(2) Migratory Bird Treaty Act - to protect migrating birds from landing in a chemical slush pit; oil companies ar required to cover such open pits w/ nets; enforcement is very slack(3) National Environmental Policy Act - applies to any major federal action, including drilling on federal land; thus, an initial environmental assessment is required and if a major impact will result, an environmental impact statement is required

STATE REGULATION

State environmental law tends to be driven by federal law w/ states given the power to regualte if they enforce regulations that are equally as stringent as the federal ones.

Factors involved:(1)States when allowed to take over this area choose to do

so(e.g. Safe Drinking Water Act)

(2)The imporatnce of the oil & gas industry to a states economy(3)State population (more people, more regulations)

Two main issues reside here:(1) To what extent will federal regulations dictate state

regulation & problems when not coordinated.- state regulations tend to reflect federal policy- If a state doesnt model its regulations after the federal ones, then enforcement wont be delegated. Huts, two systems of regulation will exist and their requirements must also be met.

(2) Who is responsible for carrying out regulations?- due to the number of transfers in the oil & gas industry identifying the operator is often times very difficult; this is particularly problematic as when the life of a well draws to a close small, often-times insolvent companies are the operators and can not afford to pay for the plugging- an attempt to adopt the CERCLA approach was made, but struck down in Petrofina- however, the definition of an operator has been expanded

- anyone w/ an interest via a joint operating agreement can be held responsible as an operator

III. The Oil and Gas Lease

The lease is a conveyance in that it is the instrument by which the mineral owner, who owns the rights to explore for oil and gas, conveys the right to an oil company, reserving to himself a royalty interest in production. The law views the conveyance not as a typical lease, but as a fee simple determinable in the mineral estate.

A. Overview

EXAM NOTE: What sorts of things will parties bargain for?

1. Bonus

The lessor is usually given money up front for the lease itself, paid by the lessee at the time the lease is executed. This is refered to as the bonus and is computed on a per acre basis.

The amount of the bonus will vary, depending on the prospect of oil. There is an element of risk involved. By accepting a bonus now, the lessor is gambling on the chance that she is giving up a higher bonus in the future (if oil or gas is discovered nearby, for example). If a wildcat, then lower bonus b/c it is speculative.

2. Term or duration

The lease is usually divided into two periods.

a. Primary term

Runs for a specified number of years. At the end of this term the lease will end unless there is production.

The lessor wants a short primary term because no drilling is necessary to maintain the lease during the primary term. The lessee, on the other hand wants longer primary term for the same reason.

Historically, the primary term has been getting

shorter (today it is 2 or 3 years), probably the result of better geology.

During the primary term, two types of clauses operate to end or continue the lease.

i. Unless clause

If drilling has not commenced within 1 year of the execution of the lease, the lease will terminate unless the lessee pays a delay rental to the lessor.

This delay rental is also computed on a per acre basis, but it is probably a mistake to bargain for a high delay rental, because the lessee can just walk away and not pay.

ii. Or clause

The Or clause is another type of limitation on the primary term. This will be discussed more fully later. Basically, it provides that the oil company must either drill or pay delay rentals. It removes the option of not doing anything and letting the lease expire.

iii.Paid-Up Lease

No delay renatl provision at all as it is included in the the bonus. This option is used mainly w/ short-primary term leases. Reduces the transaction costs for a large company.

b. Secondary term

Continues the lease indefinitely, as long as there is production from the land, or the site is pooled with neighboring producing land.

3. Royalties

Rights to a set fraction of the production or sale price of production without deduction for the cost of drilling or operating the well. The most common

fraction today, as has been for over 50 years, with few variances, is one eighth.

The notion that a royalty interest is expense free is a slight overstatement. Some expenses must be borne by the landowner. For example, severance taxes and treatment of production must be borne proportionally by the lessor.

4. Surface use

The owner, if he owns the surface estate as well as the mineral estate, may be concerned with protecting the surface for other uses, like farming, etc... See the following detailed discussion of surface use.

B. Surface Rights Granted by the Lease

EXAM NOTE: If I'm lessors lawyer, I need to bargain for provisions giving me special protections for the surface.

This is the major conflict certain to arise is when the oil company shows up to begin work and reality sets in. Clause 1 of the form lease encompasses broad surface rights on the part of the lessee. This lease seems to presuppose rural land. There is no provision for leasing of improved land near a city, or land with agricultural use. If such land is leased, you would need a different form.

Another common source of conflict regarding surface use arises because the owner of the mineral estate, i.e. the party doing the leasing, is often times not the owner of the surface estate. Accordingly, the owner of the surface estate has no bargaining position going into the lease.

1. Dominance of mineral estate

The rights of the mineral estate to use the surface for the development of the mineral estate are dominant to the rights of the surface estate, subject to some limitations discussed later. Even if damage is caused to the surface, the mineral estate owner has no liability. It is assumed that a certain amount of damage is contemplated at the time of conveyance and is, therefore, reflected in the consideration. Also implicit in this dominance rule is that the mineral estate is more valuable than the surface.

Traditionally: Surface owners can't get damages b/c mineral owner is exercising her rights.

A common source of conflict results from "slush pits". Drilling requires certain effluents, such as drilling mud, water, etc... The oil company needs to dispose of these fluids and the best way to do so is by use of a slush pit. The landowner cannot enjoin such a pit.

a. Implied rights

In addition to the express surface rights set out in the lease, the lessee has certain implied rights to use the surface as reasonably necessary to conduct normal drilling and production. Surface damage is not enough to warrant enjoining the lessee from carrying out his implied rights.

Reasons for this implied right:(1) minerals are more valuable than the land itself;(2) vestiges of Spanish law where the sovereign owned all the minerals; however, this reason provides no basis outside of the SW states;(3) easement by necessity.

2. Restrictions on surface use

Actually, the above overstates the relationship between the parties. There are several restrictions on the lessee's use of the land which are implicit in the "reasonable use" standard.

a. Negligence

The lessee cannot negligently injure the surface. In Brown v. Lundell, the Tx. S.Ct. imposed liability on a lessee for negligent pollution. The court stated that if the lessee exceeds the rights granted to him, he becomes a trespasser, and thus is liable for his negligence.-Area polluted was outside area leased.

b. Reasonably necessary

Common Law Rule:1.couldn't use more of land than reasonably necessary2.Use itself must be reasonable (non-neg).The use of the surface must be reasonably necessary to develop the mineral rights. Otherwise, the surface owner will be entitled to damages for the lessee's excessive use of the land.

Santana v. Henderson:Driller let oil spill poison cattleCt: rvsd holding for landowner

1. must show driller used more space than needed2. or negligent outside space necesary.

Note: Still plenty of cases where ct says Oil Co. is simply abusing the space necessary for its obligation.

What is reasonable is a fact driven question. However, courts have allowed the right to occupy land in many ways at those locations necessary for production. They have also allowed consumption of the surface where necessary. For example, the use of surface water and clay has been allowed.

c. Accomodation doctrineThe lessee's use cannot be viewed in the abstract. It must be viewed with an eye to the existing use of the surface by the surface owner. If there is a way to accomodate the owner's surface use, then the lessee must try to do so.

RULE: Specific lmitation on implied rights-if there are 2 or 3 ways to do things, it must do so in a way that least interferes with the surface owners preexisting use.

See Getty Oil v. Jones. P bought the surface of land which was already subject to a lease. P installed an irrigation system for farming. After the system was installed, the oil company installed pumps that blocked the irrigation pipes. P sued, claiming D should use different pumps. P won based on the accomodation doctrine.

Under Getty, there are three requirements that must be met for the lessor to invoke the accomodation principle.

i. There must be an existing use of the surface;

ii. The lessee's proposed surface use must impair the existing use of the surface; and

iii. There must be a reasonable alternative available to the lessee.

d. Limits on the accomodation doctrine

The reasonable alternative available to the lessee must be available on the leased premises. In Sun Oil v. Whitaker, the Tx. S.Ct. held that the lessee, who needed water for his water flood project, was not required to purchase water off the premises. The accomodation doctrine was limited to those situations in which there are reasonable alternative methods that may be employed by the lessee on the leased premises.

*Traditonal Statements of Implied Rights of Mineral Owners is Cicumscribed by 4 or 5 Factors

1. Contractual modifications

Parties can agree to arrangements other than the common law presumption of the dominant mineral estate. e.g. damages clause for surface injury.

Problem: Relying on K provisions. Surface rights owner may not be a party to bargain with the Oil Co. Rights may have been severed.

2. Statutory modifications

Many states have enacted statutes which effect the dominance of the mineral estate.

a. Subdivision statute (Tex. 1984)

Applies to counties with certain minimum populations. The idea is that if a developer is planning a subdivision no greater than 640 acres, then he can limit all O&G production in the subdivision to 2 acres per each 80 acres. The Commission determines the most reasonable sites.

This statute reflects the rising value of surface estates and the corresponding increase in real estate lobbying power.

b. Surface damage statutes

These force the lessee to pay for any damage to the surface, even if the lessee's use was reasonable. This forces the lessee to reach an agreement with the landowner as to the amount of damages; otherwise, the lessee must go to court.

c. City ordinances

May regulate the location of drilling sites within the city's jurisdiction.

4. Minority view

A minority of states (e.g. Ark.) have nearly overturned the dominance of the mineral estate, and have held that the mineral owner has an implied duty to restrore the land.

C. Duration of the Lease

*Maintenance of the Lease in the Primary Term

The duration of an O&G lease is determined from the habendum clause (clause 2 in the form lease). There are two parts to the habendum clause: the primary term and the secondary term.

As noted earlier, the primary term is a fixed term of years during which the lessee has the right, without any obligation, (under the unless lease, more later) to explore for or drill for O&G. The typical language to grant the primary term is illustrated in the form lease: "subject to the other provisions herein contained, this lease shall be for a term of years from this date and so long thereafter as oil and gas or other hydrocarbons are being produced ..." This clause should be read in conjunction with the delay rental payments clause.

1. Delay rentals

Clause 5 of the form lease indicates that if operations for drilling are not commenced within one year, the lease shall terminate unless before such date the lessee pays the lessor

delay rentals. If such rentals are paid, drilling may be deferred for one year. Similarly, drilling operations may be further deferred for successive one year periods during the primary term hereof by payment of the delay rental.

a. Unless Clause

This is the most common form of the delay rental clause. It is called an "unless clause". Under this form, the lease automatically terminates unless the lessee drills or pays. Thus, the lease is like a fee simple determinable. There is no obligation upon the lessee to do either of these things.

b. Saving Lease in Equity or Estoppel

Upon the lessee's failure to drill or pay the right amount on time, the lease will automatically terminate. However, the oil company might be able to maintain the lease through either equity or estoppel.

i. Example 1

One situation is where the lessor leases to the lessee and subsequently conveys the land to A, but the conveyance is poorly worded and the lessee is not clear who to pay delay rentals to. The lessee interprets as best he can, and sends payments accordingly. A then tells the lessee that he got it wrong, and the lease is terminated. Because the lessee has been misled, and A knew of this, A is estopped to argue termiation.

To protect against this, when there has been a division of rights, a lessee will typically send a division order to all the parties so they can spell out the new interests. Then, the lessee makes payments based on that division.

ii. Example 2

Another case in which courts often allow the lease to continue is where the lessee fouls up all by itself, and sends a check that is incorrect because of a clerical error. The lessor accepts, and says nothing. The courts find an estoppel

there, because if the lessor had informed the lessee of the error, the lessee could have corrected the error.

iii. Example 3

What if the payment is late? Two theories:

(1) Automatic termination

Under this theory, there is nothing to estop the lessor from doing. The lease terminated under its own force, and the parties are powerless to stop it.

(2) Revival

Under this theory, the lease terminated, but was "revived" when the lessor accepted the late payment.

c. Savings Clauses

Note:If you represent a Oil Co. you need to assess this to protect it from accidental termination.

Clauses designed to prevent the automatic termination of a lease upon non-payment of delay rentals.

Wording must be meticulous. For example, one stating that "failure to pay delay rentals will not result in termination without notice" will be invalid because it is wholly inconsistent with the assumption of a fee simple determinable. It changes it to a fee simple condition subsequent. Similarly, one saying "failure to comply with obligations will not result in termination without notice" will be invalid because delay rentals are not obligations - they are optional.

One clause which has been found to work is one which says that "if lessee in good faith attempts to pay rentals but does so incorrectly, the lease will not terminate without notice".

d. The or lease

The "or clause" does not automatically terminate the lease upon the lessee's failure to commence drilling operations or pay rentals in a timely fashion. It merely imposes an affirmative duty upon the lessee to do one or the other. Failure to do so does not terminate the lease, but opens up the lessee to liability for breach of contract.

This type of lease has been around as long as the unless lease, but is not as popular with oil companies because there is no option to do nothing. If the economy takes a down turn, the oil company must keep paying or drill. Thus, he is stuck with the lease during the primary term.

You could remedy this concern with a surrender clause enabling the lessee to get out of the lease by surrendering it back to the lessor. However, this still requires affirmative action on the part of the lessee. He still has no "do nothing" option as there is under the unless lease.

e. The "paid up lease"

This is a third type of lease which does not provide for any delay rentals at all. Thus, the primary term will not lapse at all. This is an ideal solution for oil companies who do not like the dangers of the other two types of leases. But, lessors don't like this type of lease because no drilling will probably be done. This type of lease is thus only common where the primary term is short, or the land covered is small. May also occur where the land is known to be productive, because there will be little danger of the lessee not drilling.

2. Commencement of drilling operations (what constitutes this?)

Most oil and gas leases provide that as an alternative to payment of delay rentals, the lessee may maintain its rights during the primary term if drilling operations are commenced. Disputes frequently arise over what is adequate to have commenced operations.

Doesn't mean a hole is actually being drilled in the land, Just meams lessee is doing something preperatory to drilling

a hole.a. Wilds v. Universal Resources Corp.

In this case, the lessee moved onto the premises 2 days before the end of the primary term, with a rig capable of drilling only shallow wells. This rig was OK to start drilling, but it was slow and would not be enough to drill to final depth. The lessor claimed that the lessee had not commenced drilling operations.

The lessee responded that he had commenced operations by moving the rig onto the premises. He said that drilling slowly is not a limitation resulting in termination; rather, if anything it is a breach of an implied covenant (later). Breach of the implied covenant will not terminate the lease (unless the lessor has given notice and lessee fails to correct), it will only give rise to damages.

The court rejected the lessee's analysis. The court held that the commencement of drilling has four requirements - good faith, diligence, physical activity, and means and ability to keep operating.

i. Good faith (co. is doing work with the intent of going thru with the process, not simply delaying it until someone else discovers oil)

The fact that the lessee waits until the end of the primary term does not, in and of itself, establish bad faith.

ii. Physical Activity

-Mainly to Provide NOTICE

Courts are fairly liberal with this issue and don't require an actual hole in the ground. Reasonable preparations are enough.

Reasonable preparations, however, must be adequate to give the lessor notice of the commencement. For example, simply getting a drilling permit will not suffice whereas bulldozing an area will.

iii. Diligence

The lessee must be acting diligently in continuing to drill.

iv. Means and Ability to Keep Operating

The lessee must be capable of continuing the operations.

Q: Suppose ct. concludes that diligence is a covenant. Here-Fee Simple Dterminable

Special limitation: No drilling operations-lease terminatesCovenant Breach-No loss of lease-damagesThats why lessee args its a covenant.Lessor always argues for a limitation.Lessee always argues for a covenant.

Q: When would summary judgment be appropriate?Most likely when there has been little or no physical activity.

Q: Why have such a bright line rule on physical activity?It puts the lessor on notice and allows him to negotiate a new lease ASAP w/ some degree of certainty.

b. Cessation of operations during primary term

Above, the discussion centered primarily on what is sufficient to continue the lease during the primary term into the secondary term. But what happens if drilling is commenced, and then stops (say for a dry hole) during the primary term?

Generally the lessee won't have to pay the delay rental for the year in which operations occurred. But, if the lessee fails to do any more drilling, he will have to pay delay rentals due 60 or more days after drilling has finished (under our form lease).

Because most drilling does not begin until the end of the primary term, there is not much litigation over this aspect.

c. Extension into Secondary Term

Sometimes a well will be completed but production will

not have begun for some reason beyond the lessee's control. For example, he may be awaiting hook-up with a pipeline.

In such a situation, some states allow the lease to enter the secondary term. They hold that a well capable of production is sufficient. Some states draw a distinction between oil and gas. They require actual production of oil because it can be stored on the surface, but they allow an exception for the gas well waiting on a pipeline. Texas, however, would terminate the lease for either type of well (unless there was a savings clause - see shut in royalties below).

E. Maintenance of the Lease in the Secondary Term

The modern day oil and gas lease terminates at the end of its primary term unless the lease is extended and maintained by production.

1. What is production?

Production sufficient to maintain the lease during the secondary term is somewhat different from that necessary to extend the lease into the secondary term. To maintain the lease, production in paying quanties is necessary.

a. Clifton v. Koontz (Tx. 1959)

This case involved the issue of how long a once profitable well can go on operating at a loss without termination of the lease.

Here, the well was marginal to begin with. The lessee then began saving oil to use in secondary recovery operations. At that point, the well became unprofitable, because less oil was being sold. The actual loss on the well was $216 for a 16 month period. The lessor sued to terminate the lease.

The Tx. S.Ct. refused to buy the lessor's argument that the lease was terminated. The Court said that it would not look at any specific period of time to determine whether the well was profitable or not. Instead, the test is the reasonably prudent operator standard. If a reasonably prudent operator would operate at a loss

temporarily with the hope of future profits, then the lease would not terminate.

b. Court's concerns

Why should a court allow termination where the lessor is getting his royalty and the lessee is losing money, but apparently wants to continue? The courts view the purpose of the lease as drilling, production, and development for the benefit of both parties; the intent is not to allow the lessee to speculate in hopes of future profits.

c. Paying quantities

In determining whether the production is profitable or not, the lessee may deduct expenses associated with production of the well. These do not include the capital investment in the well but do include the following.

1. The landowner's royalty

2. operating expenses

3. overhead expenses

Allocation of some of these expenses to the well in question could be the key to profitability. The lessor wants all overhead allocated. The lessee wants to allocate only the overhead that would be saved if the well stopped operating. This is likely to be zero.

These two approaches represent extremes. Courts generally do allocate some of the overhead, but by some formula more in between these.

Perhaps, the best solution is to consider what costs would disappear if the well was abandoned.

Note that production in paying quantities is the rule in the majority of states. Some states, however, equate production simply with the ability to produce. They do not actually require oil to be brought to the surface. So long as a well is capable of producing and

the lessee is acting diligently to market the oil, production will be deemed satisfied for the purpose of the lease.

Included in the reasonably prudent operator standard is whether continued speculation on this well would be reasonably prudent.

Generally, if the well has had a monthly loss for 12 consecutive months, the lessor will win. However, lessor usually loses these cases and wins only against small companies. Courts continue to show great deference to the oil industry as it is considered to be in a better position to judge what is prudent than the lessor.

2. Temporary cessation of production

Acting on the premise that the parties must have contemplated temporary interruptions from time to time, the courts have held that the oil and gas lease does not terminate where there is a temporary cessation of production.

If such cessation occurs during the primary term, the lessee may have to resume delay rentals; if the cessation occurs during the secondary term, the lease will be preserved as long as the cessation meets the requirements of the Temporary Cessation of Production doctrine.

a. SaulsberryThe doctrine is illustrated in Saulsberry v. Siegel. A lease was entered into in the 1920's. The well was producing, but the pump caught fire. The lessee rebuilt the well 4 years later and resumed paying quantities. The lessor accepted new royalties for about 20 years. Then, a good producing well was drilled nearby. The lessor then treated the lease as terminated. The court held that there was no termination - the lessor had accepted the royalties. Smith argues that this case is really about estoppel, not temporary cessation.

b. Factors

The doctrine of temporary cessation has three

requirements.

1. The break is short.

2. The reason for the break is involuntary or to the benefit of both partes (such as reworking).-Cause beyong lessee's control.

3. The lessee uses due diligence in restarting

Watson v. Rochmill (strict TX approach)Price fell, lessee shut in well for four years. Then reopened well and tendered royalties-lessor accepted for a few months and rejected the rest.

Held: No temporary Cessation--Delay too long-for the wrong reason

*Estopel wasn't applied becasue lease had terminated on its own force.

c. Temporary cessation in connection with other clauses

In the form lease, clause 6 is a dry hole clause. It provides that if production ceases, the lease won't terminate if the lessee commences reworking operations within 60 days. A similar clause was involved in Samano v. Sun Oil Co. There, the court held that this time limit provides an outside limit on application of the temporary cessation of production doctrine. The clause was treated as modifying the common law doctrine.

Smith disagrees with this ruling. He does not think that such clauses are intended to apply to such things as a mechanical breakdowns. Instead, they are intended to give the lessee more rights, such as the right to stop on purpose, for less than 60 days, for any reason.

3. Savings clauses as substitutes for production

As a practical matter, the definition of "production" adopted by the courts puts a heavy burden on the lessee. A lessee, for many reasons, may find it impossible to obtain

actual production and market production (as required by the majority of states) before the end of the primary term. To remedy this, most leases include savings clauses that address the circumstances that give lessees an alternative to production.

The various types of savings clauses may be thought of as providing substitutes for production or "constructive production", because they state that specified occurrences or actions will be considered as production for purposes of the lease.

a. Shut-in royalty (clause 3)

To protect against loss of a valuable well, most leases contain a "shut-in royalty" clause that permits the lessee to maintain the lease by tendering payments during the secondary term in lieu of actual production in the same amount as the delay rentals.

The typical situation involves a lessee who has a well capable of producing, but he has not yet found a purchaser (or, in the case of gas, a pipeline hooked up). Often the amount of the payments is the same as the amount of the delay rentals. The question arises: What happens if the payment is not properly made (similar problem as with delay rentals)?

Note: Shut in Royalty clause was inserted in the lease to deal w/ problem lessees have if they discoverd a gas reservoir.-Need pipeline, if near end of term, no time to get pipeline.

Shut in allows lessee to pay royalty "as the functional equivalent of actual production".

i. Failure to pay

Greer v. Salmon - The well was not shut-in on purpose; in fact, the lessee thought the well was producing. There was a break in the pipeline between the wellhead and the meter in the pipeline. The break was not repaired for three years. The lessor discovered this, and called the lease terminated.The lessee argued that only a covenant in the

lease had been breached, and that the lease had not terminated. The court did not buy this, and read the case as requiring payment of the shut in royalties to maintain the lease.

Ct: Shut-in clause must be read in connection with the habendum clause. where production, or an equivalent must exist or the lease automatically terminates.

ii. Common ambiguities

In the form lease (clause 3), the shut-in royalty clause applies to gas wells only. Defining a "gas well" can be difficult. Does it refer to wells producing only gas, mostly gas, or a well defined by the Commission as a gas well? The lease should define the term.

Traditional language: gas only is produced-suppose all substances in ground are in gaseous form

Prof: Should allow them to shut in oil well if concerned that too much gas is coming out. Wasting it by firing it.

Another problem is when to pay the royalty. The language in the form lease states that payment shall be made "at the end of each yearly period during which gas is not sold or used." There are three possible interpretations of "yearly period".

(1) 1 year from the shut in date;

(2) the anniversary date of the lease;

(3) calendar year.

The most natural reading is the first one, but the clause is still ambiguous. Further, this date is not necessarily the best date on which to run the period because there may not be precise records as to when this period began.

LANDOWNER'S CONCERN'SA. Worried about no time lmit

1.Principle econ benefit he hopes to get is Royalty from Produciton,

BUT: Isn't shut in the same as delay rental?No: it goes on foreveriii. Useful in Oklahoma

In states where production requires bringing to surface and marketing, the shut-in royalty makes sense. In minority jurisdictions like Oklahoma, however, where production only requires the ability to produce, the shut in royalty does not make sense, because not needed, as long as the lessee makes diligent efforts to market the gas.

However, it might make the lessor happier to include one to give him the option to quit production and not act diligently for any reason.

iv. Duration of lease with shut in royalty payments

There is no limit on how long the lease can be kept in effect, as long as the payments are made, the way our form lease is written. The lessor might want to (1) increase the shut-in royalty; or (2) put a cap on the time the lease can be continued by the payment of a shut-in royalty.

b. Force majeure clause (clause 11)

Force majeure means superior or irresistible force. The term is generally applied to contract clauses designed to protect parties against the possibility that the contract cannot be performed due to causes outside the control of the parties and that could not be avoided by due care. For example, natural disasters.

The clause are designed to prevent contract breaches in a normal contract setting. However, in an O&G lease, there is really a fee simple determinable. They are used in this setting not to excuse a breach, but to cancel a limitation. Courts are largely unwilling to allow such an effect. Accordingly, when drafting such a clause you must be very careful.

A common drafting problem with a force majeur clause is one that only forgive a lessee from performing its "obligation". Since production is not an obligation,

that is, since the lessee can elect not to produce, such a clause will not save a lease from terminating.

Violating state and federal regulations which result in no production does not constitute force majeure. This provision when applicable only saves a lease until the problem can be remedied.

c. Dry hole and operations (clause 6)

Dry hole and operations clauses are designed to protect the lessee's interest where the option to drill has been exercised, but there is neither actual production nor a capability of production for a time - usually 60 days.

4. Other types of clauses and doctrines

The clauses and doctrines above (temporary cessation of production, shut in royalty clause, force majeure clause, operations and dry hole clauses) prevent a lease from terminating when there is no production.

a. Obstruction doctrine

If a lessee has a right to go on the premises, and the lessor blocks that entry, the lease is extended during the period of obstruction. Generally, the lessee needs to attempt to enter the land.

b. Lessor-favoring clauses

Most of these were designed from the lessee's standpoint. However, a few clauses favor the lessor.

i. Continuous development clause

With this type of clause, the lessor can require the lessee to begin new drilling within a certain amount of time after a different well has been completed. This type of clause is especially important where the leased acreage is large, because only one well is ordinarily needed to keep the lease in force.

ii. Retained acreage clause

This type of clause says that a well will only maintain a lease as to a certain amount of surrounding acreage. The effect of this clause is to terminate a lease at the end of the primary term except as to the designated acreage being worked.

A related item is a Pugh clause which prevents pooling of a small portion of leased land from maintaining an entire lease. These clauses are discussed below.

iii. Combination of the above

These can be used in combination to help ease the lessee's anxiety over having proved up the whole acreage but only getting a smaller advantage. With the combination, the lessee can continuously develop until he's had enough, and then the designated acreage continues, and the rest terminates.

5. Use of more than one clause or doctrine at once

There may be situations in which more than one of these will be applicable. For example, if a well is producing, and then stops, the lessee may be able to invoke temporary cessation, shut-in royalty, force majeure, and the operations clause. In such a case, the lessee had better be careful of what action he takes because if he guesses which clause is applicable different from the courts determination, he could lose the lease.

For example, in Samano v. Sun Oil Co., the lessee suffered a breakdown in machinery and began repairing it 70 days later. Lessee argued temporary cessation; but, the court held that the operations clause applied, and put an upper limit on the length of time that the temporary cessation doctrine would keep the lease (60 days).

PROBLEM #3 - Lease Savings Clauses and Doctrines

Atkinson Gas Co. v. Albrecht (1994) -

Atkinson, the lessee, owns the mineral rights to 187 acres owned by Albrecht. Atkinson has grown lax in his business practices:

(1) wasnt paying his royalties;(2) wasnt paying his one occasional employee;(3) wasnt filing monthly reports to the RRC.

Albrecht and Atkinsons employee turned off his well and sent Atkinson a letter on 12/9/91.Atkinson ignored the letter as he was still getting checks from the pipeline co. (accounting errors - must have been Coopers & Lybrandt). On 1/22/92, the RRC sealed the well.On 3/20/92, Atkinson reconciled w/ the RRC. No production from 12/9/91 thru 3/20/92. Thus, Albrecht claims that the lease terminated.

Albrechts argument:No production for more than 60 days, thus termination.

Atkinsons arguments:(1) Temporary Cessation in Production (CL doctrine) - accidental random events are assumed to be contemplated in a limitation on an estate. Thus, if the cessation is temporary and grantee (Atkinson in this case) reasonably and diligently attempts to meet the terms of the limitation, the estate is not terminated.[Problem in this argument is the diligence requirement - he completely ignored the letter](2) Lease Clauses - The Court concluded that the operations clause in the lease superceded the common law doctrine of temporary cessation. The operations clause contains a 60 day window to restart operations. The lessee must rely on one of the savings doctrines noted above. Very hard for him to win in this case due to his complete lack of diligence over the years.

BIG POINTS

A Deed not really a lease- conveys a FSD in the minerals, thus it ends automatically- many occurances can prevent termination (the limitations)- an easement construction would create 2 major differences (e.g. Oklahoma - OU Sucks):

(1) a well is prserved if a well is capable of producing in paying quantities

(2) paying the shut-in clause is a covenant not a limitation

- in Oklahoma, a FSD for the primary term and an easement on condition subsequent in secondary period

6. POOLING

When two are more tracts of land are combined to create a drilling unit, it is referred to as pooling the tracts. Pooling can be either voluntarily or by force of statute.

a. Lease pooling clause (clause 4)

An oil and gas lease commonly contains a pooling clause. The pooling clause authorizes the lessee to pool the leased premises with other lands on both the lessor's and lessee's behalf.

Absent such a pooling clause, the lessee does not have contractual authority to pool the lessor's interest, but the lessee may obtain a compulsory pooling order.

Serves as a savings clause: Lessee leases 200, he can pool 20 from it and twenty fom neighborin tract, drill one well on the unit, and maintian both leases.

-"Constructive Production"production from well is treated as coming form both leases. Allocated on surface/acre basis.-regardless of where drilled.

i. Types of Challenges

Challenges to a lessee's actions under a pooling clause will fall into one of two categories.

1. lessor will claim that the action does not fall within the authority granted by the clause (e.g. units too large - lessor wants small to get more % of royalty, lessee wants large to increase allowable).

2.or he will claim that there was a lack of good faith.

Note: If lessor has small tract, he won't want it pooled with lage tract, b/c his royaly will be substantially diluted.

Challenges to the authority to pool will typically be tough to assert because courts generally read pooling clauses very broadly. One case in which the challenge was successful, however, was Jones

v. Killingsworth. But Smith says that this opinion represents a minority view.

ii. Jones v. Killingsworth

The pooling clause limited the size of units to 40 acres for oil and 640 acres for gas, but the government could prescribe or permit larger units and the units created thereafter may conform in size to those prescribed. The Commission establish 80 acre units for oil but permited up to 160 acre units. Lessee attempted to pool 20 acres into a 160 acre unit.

The issue centered on the "permitted v. prescribed" language of the lease. The court held that the lease meant that the unit of 40 acres could be enlarged to conform with Commission requirements (those "prescribed") not allowances (those "permitted"). Thus, the maximum pooled unit could be 80 acres here. The lessee had therefore exceeded the authority in the lease by violating the size limitation.

Note that his same language is in the lease in the forms manual. RRC reqs 80 to drill. lease allows poolin of tract larger than 40 only if prescribed by rrc. May go up to 160 deosn't equal prescribed, just permitted.

iii. Challenges on good faith

Due to the broad reading given to pooling clauses, courts require that lessees act in good faith when exercising their rights granted under them. There are three main challenges which commonly show bad faith.

1. Pooling after production

Once production is obtained, pooling the producing land with other valueless land to reduce the landowner's royalty will be a badge of bad faith. However, circumstances might justify such actions. If the pooling decision is geologically sound, there is

almost a presumption of good faith.

2. Pooling at very end of primary term

Pooling just before expiration of the primary term is also a badge of bad faith. However, if it makes sense to do so, it will be allowed. For example, if drilling costs are not economically justified, pooling might be a valid way to proceed.

3. Gerrymandering

Pooling a small portion of the leased land in a unit to tie up a much larger lease is also evidence of bad faith. Pugh clauses, however, make this concern irrelevent.

Prof: This doesn't mean a lessee acts in bad faith just because he pools to save a lease. Just means this cannot be the sole reason. I lessee has further drilling plans he may be able to pool to temprorary save the lease.

4. Reducing Unit Size.

Must lease tract in the unit in its originalform.

iv. Estoppel, ratification

If the lessee exceeds the authority, the lessor may still be estopped to contest if he accepts the pooled share of royalties. Further, the lessee may issue a "division order" with the fraction of royalties given in pooled terms, though less than authorized. If the lessor signs, this may be ratification of the pooling.

v. Pugh clauses

This type of clause allows the pooling arrangement to only maintain the lease on the pooled acreage. Land outside of the pooled acreage is not considered to have production on it.

The wording of Pugh clauses must be meticulous to be effective. We have seen one that requires delay rentals to be paid be ineffective to cancel a lease after the primary term when delay rentals are no longer required. We have also seen one that referred to units created hereunder that a court refused to apply to units created by force of a statute.

(a) The Pugh clause only saves a lessor if his land is pooled. If a lessee only uses a small portion of land of a large lease without pooling, the lessor will need a retained acreage clause to terminate the lease in regard to the other areas.

(b) Lessees are usually unwilling to give retained acreage clauses because they will have to fully develop a lease to keep it. They might, however, agree to a continuous develpoment clause which allows them to keep the lease only so long as they continue to drill.

Voluntary Pooling w/ Third Parties

Declaration of Pooling: Purpose is to put third parties on notice as to whats happening.

No Notice:

Community Lease2 neighbors sign same lease describing their land. Its communitized and production from either tract is shared on a surface acre basis.

a. Voluntary Pooling: Share on basis of % acres given to the pooled unit. X has 600, his 40 is pooled in 160 rig. gets 1/4

b.Community. A 80 B 80, each get half even though drilling unit is only on 40 and its all on A's land.

c. Cross conveyancing theory.

b. Forced pooling

Forced pooling results from a decree of a regulatory agency. A forced pooling act largely eliminates the need for small tract exceptions to prevent confiscation.

Suppose the standard drilling unit is 40 acres. Exxon has 20 acres and could get an exception to prevent confiscation. But Exxon does not think that a 20 acre tract will be profitable because of the lower well allowable. So, Exxon wants to reach an agreement with his neighbors who have 10 acres each. They refuse to agree, each wants his own well. At this point, Exxon can go to the Commission and request forced pooling.

i. Texas

Recall that in Texas, while a rule 37 exception is still available for small tracts, it is really a meaningless right because well allowables are reduced to make drilling on a small tract infeasible. The decisions abolishing favorable well allowables for small tracts essentially prompted forced pooling legislation.

In Texas, the party seeking forced pooling must show that he has exhausted voluntary pooling efforts. Also, forced pooling is only available on reservoirs discovered subsequent to Normana. On fields discovered prior to this time, well allowable allocations for small tracts are still very favorable.

By exhausting voluntary pooling efforts, a party must have made a fair and reasonable offer. If there is an existing well that the party is trying to muscle into, the other parties might want a premium for having borne the drilling risk. This seems reasonable. Also, they will probably want some assurance the land being offered is productive. This too seems reasonable. If the previous offers were not fair and reasonable, the Commission has no authority to force pooling.

-offer not unreasonable b/c it has some

nonproductive acreage.

ii. Sharing production

The Texas Natural Resources Code provides that normally production from forced pooling units is divided on a surface acreage basis, unless a forced party can show it is unfair. In our example, Exxon would get 50%, and A and B would each get 25%.

iii. Sharing Costs

The Code states that if anyone is forced into a unit, then he is given an option on how to share costs.

(a) Pay-as-you-go

Under this option, the forced party can pay his proportional costs as they accrue. This option is always offered. However, if a party is willing to accept it, he will probably agree to voluntary pooling in the first place.

(b) Carried

The forced party might have the option to be carried. That is, he can have his share of costs deducted from his share of production. Because such an option removes the risk of a dry hole from the forced party, almost all forced pooling statutes provide for a risk penalty. Typical penalties range from 100% to 300%.

Texas: Max. penalt is 100% of your share of costs.

(c) Assignment

A third option, available in Oklahoma, is that the forced party can assign his interests to the other parties for cash compensation or an overriding royalty.

Texas Forced Pooling ActReaction to cases where SC well allowables favoring small tracts are confiscatory.

Problem: Owners at loggerheads. Independents worried about being left out. If they get permit, not enough production to make it worthwhile.

Solutions:Oklahoma: Designate units and force everyone into them; Tx rejected this

Texas: Statutory Conditional Show applicant has made a fair and reasonable offer of voluntary pooling.

Rememeber Texas doesnt have forced unitization, but does have forced pooling resulting from the Rule 37 exception and the ability of a lessee to designate lands to a well w/i reasonable limits.

Forced pooling results from lands that resulted from voluntary subdivisions, and economic unfeailibty to not pool given well allowables. A private remedy in Texas as the RRC can not force pool on its own initiative.

iv. Muscling in

The Texas Act supposes the normal situation to be where there are a few tracts smaller than the standard unit. One landowner or lessee tries to achieve voluntary pooling; failing that, he can go to the Commission and get a forced pooling order.

Two showings needed to muscle in:1)No one made you a fair/reasonable offer2) You made it to one of them

a. Applicant argues:inceased production b/c of increased surfcae area.b.Resistor; Were not capable ofproducing more-A's tract doesn't overlap reservoir

Carson Case: Old lease w/out Pooling clause, lessee then turns forced pooling statute against his own lessor.

Facts: C, lessor has 1/8 Royalty. Lessee needs his land.Lessee asks C to pool on same basis as other landowners, youll get 1/8 royalty on 1/4 of production. C said no way

TxSc: no one could find this fair-since lessee already designated sight on lessor's land.

Almost as an afterthought, the forced pooling provisions also enable a party to muscle in on an existing well. The Act says that if the small tract owner has not been given a reasonable opportunity to pool voluntarily, he can force his way into an existing unit. This provision of the Act is the most litigated.

NOTE 1 - If an applicant is surrounded by pooled units, he can probably choose which one he wants to join.

NOTE 2 - When an applicant joins, the royalty share for the other participants will decrease; however, an increased allowable may offset the decrease.

c. Pooling With Multiple Lessees

The preceding discussion assumes that the same lessee is pooling land with other land he has leased. If he is not, then the different lessees must negotiate a Joint Operating Agreement. This will define how costs and production are to be divided between the lessees.

F. Computation and Payment of Royalty

The lessor's single greatest benefit under the oil and gas lease is the provision for a royalty. The royalty provided to the lessor gives him a stated fraction (typically 1/8) of gross production, free of the expenses, unless the minerals must be treated somehow, for which the lessor must bear his proportionate share of the cost.

Payment of the royalty is the only obligation in the oil & gas lease; all others are simply covenants w/ damages as the remedy.

Only expenses are 1)production taxes 2)post-production cost

Oil is payment in kind. gas is still owned by lessee, he accounts to lessor.

I. Often times, the payment of royalties can be very compliated and involve multiple parties and transactions. Errors sometimes do occur and a lessor will respond to an error in payment as grounds for terminating the lease (in an attempt to get a new bonus or a better royalty). What can an Oil & Gas Co. do to protect itself from this?

(1) send payment in advance(2) use a bank as the lessors agent and make payments directly to the bank(3) division order for delay rentals (discussed below)(4) a specific clause in the lease (but must be very careful given the odd constructions courts tend to give oil & gas lease - anything that they consider new & odd may simply get ignored)

1. The market value problem

Because gas can not be effectively stored on the surface, gas royalties are paid in cash rather than in kind. Lessors are at the mercy of their lessees for marketing the gas produced. Much litigation arises about what the royalty should be based on - the long term contract price or the current market price. With oil royalties, it is harder for the lessor to complain because he could always sell the oil himself. Oil royalties are paid in kind. Disposition of royalty without lesor's consent is conversion. can either pursue lesseee or purchaser for recompensation.

a. Lease language

The classic language is in the sample lease (clause 3) as follows: royalty for gas produced from said land and sold or used off the premises the market value at the well of 1/8 of the gas so sold or used, provided that on gas sold at the well the royalty shall be 1/8 of the amount realized from the sale.

i. Literal construction

Construing this language literally, if gas is sold off premises, the market value is to be used; otherwise, the amount realized from the sale is to be used.

ii. Rationale for split language

The idea behind this language was that if gas was sold off the premises, then it usually meant that the gas had to be treated at some additional cost to the lessee. The sale price would reflect this treatment and be somewhat inflated. Using the market value prevented the lessor from benefiting from any work the lessee did to make the gas marketable.

b. When is gas sold "off the premises"?

Texas courts generally construe this language literally. Off the premises means off the lease. Thus, in Texas, the lessee can avoid having market value be the measure if title passes at the wellhead.

However, in Piney Woods Country Life School v. Shell Oil Co., the court here did not allow lessee's actions to automatically determine how to calculate royalties by specifying where title passed. The court held that if the sale price takes into account the fact that the gas is treated, then the gas is effectively sold off the premises, and the royalty is to be computed on market value and not on the sale price.

c. What is "market value" for off premises sales?

There are two approaches for determining what market value is.

i. Lessors (sale price is irrelevant)

Lessors argue that the market value should be what similar well head sales are going for. This would be an amount which reflects current inflated prices.

ii. Lessees (Sale price - my proportional share of making the gas marketable)

Lessees argue that the market value should be the off premises sales price less any costs of treatment. This way, if they are stuck in a disadvantageous long term contract, the royalty will reflect the disadvantage.

States are split on which approach is correct. However, today it does not usually matter because the two amounts are about the same for two reasons.

First, a variety of factors have combined to make spot prices and long term prices the same: gas market depressed, long term contracts no longer used, deregulation of industry did away with interstate -intrastate variances.

Second, when pipelines purchase gas now, they make the parties sign DIVISION ORDERS which tell the pipeline where to send the royalties which are based on the contract price. A party signing such an order precludes themself from challenging amounts received.

c. When is a sale made?

In Texas Oil Corp. v. Vela, the court held that market value referred to market value at the time of production rather than when the applicable sale contract was made. Because of wild fluctuations in gas prices, this could make a very big difference.

Lessees objected, saying that this is nonsense. There is no "spot market" for gas; gas can only be sold by long-term contracts. So, the courts should be looking to the original contract to determine market value. If

the original contract was fair and reasonable, then it should be OK.

In Tara Petroleum Corp.v. Hughey, the court took the position of the lessee above, finding the Vela rule unfair because if prices are rising, the lessee must pay the lessor an increasing percentage of the total revenue. Some states, La, Ark, followed this. But, Texas went with the lessors.

Again, division orders make this inquiry largely irrelevant. Basically, the market value problem has just about run its course.

Division Orders

A. Document that sets out fraction of sale price of production that each owner is entitled to.

Tells lessee whom to account to.

B. Why use a Division Order?1.Purchaser wants to know who owns what-Needs to rely on it when it accounts

2. Reinforms conveyances after the lease is executed [e.g. lessor grants as a gift a portion of his royalty to his two children b/w creation of the oil & gas lease and production]

3. Purchaser doesnt want do a title opinion regularly

Three D.O. Problems

A. Fractional Interest MisstatedB. Provides for fraction of sale price (lease says markey price)C. Contains language that appears to effect some change of the lease.

A. Fractional Interest Davinda Case

Facts: S sells land to G, reerves a royalty (non-partic)-Instead of saying 1/2 of roylay it says 1/2 royalty. i.e. 1/2 of gross production!

Strata readsin of. gives 1/8 Roy to lessor, divinda family gets 1/16 for 7 years. Sign a DO. Find out rescind Do and demand 1/2 of production.

Strata args: DO is binding unil its revoked

TXCTS: If mistake on multiplier-your stuck until you rescind

Here it is different-Lessee Lost-Lessee got $ that should have gone into lessor's pocket.

B. Market Price vs. Sales PriceExxon v. Middleton - the sales price is less than the market price. The accounting in the lease is more favorable than the accounting method in the division order. Middleton accepted their royalty based on the less favorable method for 3-4 years. Middleton claims it is due the difference. Court found for Exxon assertig that the division order is binding on previous payments, but Middleton can revoke the division order at will and redo the division order for future payments.

C. DO Changes terms of the lease.DO says payment to owners should be subject to terms of any applicable operating agrement...M and T are lessees-2 leases. Drill on S's land leased by T under pooling agree,ment. T wants to sell gas. M says no. Create "balancing agreement"-T gets credit for all gas now, once M sells he can make it up.

Lessor upset: They say to lessor you signed DO and it said it was subject to terms of agreement

Response: Law passed- have to sign DO,content is ltd.

Why should a lessor sign a division order statement?- lease doesnt require it- lessor doesnt want to risk altering the terms of the

lease- but Division Order Statutes dont require a lessor to sign but the payee may demand proof of title; a division order must contain the names of the payees, % of interest as a decimal, Social Security #, and a clause stating that the division order does not change the terms of the lease.

2. Split stream sales

The situation is this: two neighbors have pooled their tracts, and have drilled a single gas well. The neighbors decide to sell the gas to different pipelines, but the sale prices are different. The problem is then how to compute the royalties owed? The lessor with the higher sale price will want the royalty based of sale price; the neighbor wants the royalty based on market value. Two common formulas to compromise:

a. Weighted average

Average the gas to each pipeline and multiply by the sale price. For example, 100 Mcf sold to pipeline A for 1.00/Mcf; 150 Mcf sold to pipeline B for 2.00/Mcf. The weighted average will be 100 + 300/250 = 1.67/Mcf. This will be desired by lessor to pipeline A.

b. Tract allocation method

Under this method, half the gas is allocated to each tract, and each lessor gets his royalty based on whatever he can get for his half. The lessor to pipeline B will prefer this.

Most voluntary pooling clauses support the "tract allocation" method, but still sometimes see the weighted average method.

3. Take-or-pay controversy

A take-or-pay clause is one sometimes included in a contract between a lessee and a gas pipeline whereby the pipeline agrees to take a certain quantity of gas, or else pay for that gas anyway. In the future, the pipeline may receive credit for a portion of the gas paid for but not yet taken - 5 years is the typical cut-off period for credit.

Under the National Gas Policy Act, price regulations of natural gas were in effect, so the major bargaining piece in a K b/w a lessee and a piepline was the take-or-pay percentage. Eventually, the high take-or-pay clauses led to increased drilling (thus, regulated prices and guaranteed

payments). Local distributors of gas (who bought gas from the pipeline) had to raise prices; industry then threatened to switch fuel types. The local distributors were locked into deals w/ the pipeline to purchase natural gas at a price based on the pipelines purchases provided the lcoal distributors could pass on the costs to consumers. Under the Reagan Administration 2 changes occurred:

(1) pipelines were forced to become common carriers;(2) pipelines had to let the local distributors out of their Ks.

Thus, pipelines got stuck b/w the deals made w/ the lessees and an inability to pass on the costs to distributors. To solve their problem lessees and piepleins settled the outstanding Ks and renegotiated their deals.

A common controversy arises about whether or not the lessee must pay royalties on take-or-pay settlements received. Amounts which are recoupable are uniformly treated as being subject to royalty. However, non-recoupable amounts are treated differently by different states.

Settlement of Take or pay claused

1.Damages based on price for past underpaymentsa. buy down K price

2.Recoupable take or pay clause3.Nonrecoupable take or pay

Lessor: Some settlement is allocable to my land.Lessee: The take-or-pay cluase was simply a method of shifting risk and the settlement is not actual production as required under the lease

Lessors generally lost.

Diamond Shamrock (Fed precedent at the time)1)These payments dont relate to gas that is produced-no roy.2)Look to purpose of take or pay.

a.Assumes producer needs min cash flow in exchange of committment to pipelineb.nada to do with the lessor.

Frye Case: My lease provides for Oil roylaty as its produced and sold, but provides for gas royalty as its sold. (different than Diamond shamrock)

Q: When was it sold?A: As soon as hey entered into 20 year K. So every element of the settlement relates to the sale price.

Prof: its true it didn't say word "produced" at it said "sold at wells"

a. Frey v. Amoco

In this case the Louisiana court ruled in favor of the lessor and granted royalty on the take-or-pay payments. It did so relying on the royalty clause. The clause based gas royalties on "the amount realized from sales" whereas it based oil royalties on amounts produced. While clearly the gas was not produced, it was sold.

A second reason advanced by the court was that the purpose of the oil and gas lease - the joint development for the benefit of both parties - would otherwise be frustrated. Also, the court noted that to treat recoupable amounts different from non-recoupable amounts would create incentive for tampering with settlement agreements, a document to which the lessor has no input.

b. Killam v. Bruni

In this Texas case, the lessors lost their argument. The royalty clause based payments on gas produced. Since take-or-pay settlements by definition are not for gas produced, the court held no royalty need be paid. the case is currently up for appeal.

c. Recoupable amounts

While all states will give royalties on recoupable portions of a tak-or-pay settlement, the question still arises as to when it should be paid - at the time of settlement or at the time of recoupment. Both the time value of money and the future financial stability of lessors make this an issue.

The Louisiana court held that you do not get the royalty until the gas is actually taken. This seems to be the more reasonable approach.

A second controversy regarding take or pay clauses was whether or not they were even enforceable. Some argued that they were subject to force majeure - factors beyond our control prevent us from acting under out contract. The "factor" was the collapse of the gas market. Courts held that if decline in demand is a force majeure event in this context, then the take or pay clause has no meaning.

4. Remedies for nonpayment of royalties

The basic lease does not terminate if royalties are unpaid. The lessor's remedy is a contract action, in which he can get back royalties plus interest.

If the lessee goes bankrupt, the lessor becomes an unsecured creditor in most states. However, Texas has added an amendment to the UCC which gives the lessor some security interest in O&G sold.

5. Deductability of Post-Production Expenses

Many problems can exist in selling natural gas:(1) impurities (hydrogen sulfide)(2) transportaion to the pipeline needed(3) compression costs(4) marketing costs.

Lessee bears none of the exploration and marketing costs. Lessee shouldnt have to bear any expenses once it becomes a marketable product - these expenses are allocable to the lessor (deprecitaion, overhead, etc.).

Heritage Resources v. Nations Bank -NB is a trustee for several lessors whose royalties are based on market value at the well. However, the lease had a clause in it providing for no deductions for compression, transporting & marketing costs. Heritage deducted for such expenses anyway. The Texas Supreme Court decided that the two clauses were in conflict and stated that the royalty should be based on the traditional industry term market value at the well which allowed for such deductions. On rehearing this case stood by a 1-3-4 vote. The Texas Courts are somewhat reluctant to allow freedom of K in the oil & gas context.

MAJOR CURRENT LITIGATION

Posted Price Litigation

Each field has a certain price of oil per barrell - the posted price. Lessee would buy the oil from the lessor based on the posted price. The Texas land office and other major state agencies considered the posted price was lower than the actual market value at the well; instead look to the NYMEX or other exchanges for a market value & then adjust for transportation costs and grade of oil. Also, look to see if there has been arms-lenght negotiations or collusion in the creation of the posted price. Generally, the underpayments were in the range of 2%. Thus, brought as a class action.Ps problems:

(1) getting class certification- each lease has different language (lack of commonality)- e.g. some leases dont provide for selling oil to lessees; lessee says you didnt have to sell to us

G. Miscellaneous Lease Provisions

1. Warranty clause

In several states, the lessor impliedly warrants the quiet enjoyment of the interest leased unless warranty is expressly excluded or limited. The warranty clause permits the lessee to recover damages from the lessor if there is a failure of title.

2. Proportionate reduction clause

The effect of this clause is to permit the lessee to reduce lease benefits to the extent that the lessor owns less than the full mineral interest described in the lease. This clause and the warranty clause are mutually supporting - the warranty clause authorizes the lessee to collect back bonus payments made if it suffers losses as a result of failure of title; the proportionate reduction clause authorizes the lessee to reduce future lease benefits proportionately to the extent that there is a failure of title.

3. Mother Hubbard Clause

These clause state that, in addition to the land specifically described, a lease will cover all additional lands owned by the lessor which are adjacent to the tract specified. They were developed as a protection against poor surveying. They were not intended to suck in portions of land which were not intended to be leased and Texas courts have not allowed them to do so.

III. THE LESSEE'S OBLIGATIONS TO THE LESSOR

A. Theory of Implied Covenants

HYPOTHETICAL: 440 acres. S leased to M. M drilss a couple wells, 5 yrs go by and nothin more is done.

Brooster v LangdonA. Not just express language, look to purpose of arrngement

1. Developemtn for common benefit of both parties2. Applies covenant to effectuate intent of the parties.

B.Both benefit1. Not mutually benificial if obligation to develop is exclusively on oneor the other.2. Nature of Benifits differs-Different Motives.

C. Held: Look to what a reasonablyprudnet operator would do. (not to lessee's good fih)

The typical lease does not contain any provision imposing affirmative duties or obligations on the lessee. However, the lessee does have certain obligations, arising from covenants implied in the common law.

1. Two theories

a. Professor Walker's theory (Texas)

Normally, leased premises are unproven territory, so it doesn't make sense to set out obligations of the lessee in the lease when the parties are uncertain of the presence of oil and gas and future field-wide rules. Basically, the lessor expects the lessee to act as a

prudent operator in developing, protecting and administering the lease. The implied covenants are viewed as what the parties would have intended if they would have thought of everything.

Since the covenants are based on the intent of the parties, then an express provision in the lease can negate the implied covenants.

b. Professor Merrill (Oklahoma)

Because the lessee's bargaining position is better, the lease is held to imply obligations on the lessee in order to assure fair dealing.

Here, if there are express provisions in the lease to the contrary, the provisions will not necessarily negate these obligations implied in law if the lessor can show that the provisions are not really fair.

2. Types of covenants

Basically, the lessee is obligated to act as a reasonably prudent operator. Courts have divided this general obligation into several specific implied covenants:

- to drill an exploratory well- to drill additional development wells- to protect against drainage- of further exploration- of diligent and proper operation; and- to market the product.

Texas only recognizes three implied covenants.

- protect against drainage- develop premises- properly administer the property

However, included in these three are all of the above six.

B. Implied Covenant to Protect Against Drainage

Common Scenario: Well on A's land is draining B's land; but Exxon, B's lessee hasn't drilled yet.

1. Elements of Claim

For a lessor to win a cause of action brought against his lessee for failure to protect againts drainage, he must establish three requirements.

a. Drainage

The lessor must show that oil or gas is being drained from beneath his property. In Texas, the drainage must be "substantial or significant drainage".

b. Profitable Off-set Well

The lessor must show that the lessee could have protected him against such drainage by drilling an off-set well. Further, he must show that such a well would be profitable.

The requirement that the well be profitable is more stringent than the profit standard required to maintain a lease in the secondary term. (more that production in "paying quantities"). In that context, profitability requires that consideration only be given to operating costs. Here, the lessor must show that the proposed well would have "paid-out". That is, he must show that the capital investment into the well would have been reouped.

The typical burden of proof being placed on the lessor occurs when the neighbor's lessee is different than your own lessee. If the parties are the same - that is, if your lessee is the one draining your oil away - then courts often switch the burden of proof on this point. There is a presumption that the off-set well would pay-out.

c. Notice

In many cases, courts require that the lessor give the lessee notice of the breach. In the situation where the lessor is suing for drainage which has already occurred, however, notice is irrelevant. That is, where the lessor is seeking damages for oil lost rather than specific performance to drill an off-set well or termination of the lease, the notice requirement is

often waived.

2. Other considerations

Most of the cases in this area turn not so much on the above three elements of proof, but on other factors which the lessee claims affect the duty owed, or which the lessor claims affect his burden of proof. In genral, the lessee must act as a reasonably prudent operator.

LESEE'S ARGUMENTS WHEN ACCUSED OF BREACHING THIS COVENANT a. Administrative regulations

Can the lessee defend against the lessor's claim on the grounds that the commission has found that the neighbor's well location is appropriate?

This argument has some appeal, but Smith does not like it. It tends to misstate the effect of the regulation. Regulation is general and there has been no individual finding that the neighbor's well is not draining the lessor's land. Further, while spacing regulation is designed in part to protect correlative rights, the main thrust of regulation is to prevent waste.

The botton line is that most courts do not accept this as a defense, unless the regulations somehow actually prevented the lessee from drilling an off-set well and a rule 37 exception could not be obtained (or would not be profitable because of lowering the allowable).

b. Express language of the lease

The language in the lease may restate this implied covenant. For example, the last sentence in clause 6 of our form lease seems to do just that.

Often times, such a clause will put in specific distance requirements. For example, a well within 1000 feet of the property line. In such a situation the lessee might argue that the implied covenant is trumped by the language of the lease. The lessee then only has to offset if the neighboring well is in this distance.

As previously discussed, under Professor Wlaker's theory this could be true. However, under Professor

Merril's approach, this would not work.

c. Delay rental provision

The lessee might argue that by paying delay rentals, he has avoided the obligation to drill offset wells during the primary term. Every court addressing this question has found for the lessor. The only purpose of the delay rental clause is to negate the old covenant to drill an initial test well. It will not matter either if the lessor accepts the delay rental knowing of the drainage -he is not accepting payment in lieu of the offset well, but in lieu of an initial test well.

ARGUMENTS LESSOR WOULD MAKE FOR BREACH OF THIS COVENANT

Common Lessee

If lessee and neighbor have common lessee it may have a lower burden.

a. Express Language: lessee cannot rely on express language if it is doing the drainingb. Profit: Some say here lessor need not show off set was properly drilled.c. Burden Shift: Lessee proves that RPO wouldn't hacve drilled set off (Tx rejected this).

3. Field-wide drainage

Amoco Production Co. v. Alexander (Tex. 1981) - This is the classic drainage case - fraudulent drainage situation, with a common lessee. But, this case is also unusual, because it is arguably an expansion of the covenant to prevent drainage. Here the drainage is field-wide, not just local drainage. Also, the drainage is due mostly to the geological structure of the reservoir.

Amoco had leases both down dip and up dip. The up dip leases paid a lower royalt. As the reservoir was developed, the down dip leases were drowned out by the water drive. The down dip lessors sued claiming Amoco should get a rule 37 exception to drill additional down dip wells before their landed was completely flooded out.

Amoco defended with two good arguments, both of which lost.

a. No Need to Get Rule 37 Exception

Amoco first stated that there was no requirement to seek administrative relief from spacing rules. Court said that they had to and basically reaffirmed what is discussed above.

b. Off-set well would not help

Amococ argued that if it were required to drill an off-set well, the same doctrine would require them to drill additional off-set wells on their up dip leases. In the end, everyone would get the same royalty but they would have incurred additional capital investment.

The court rejected this argument as well. It stated that as a reasonably prudent operator it must act without regard to any other additional up dip leases it may have. Besides, protecting the up dip owners from drainage would not include protecting them from losing oil that would otherwise drain under their land. It only requires them to protect against oil draining away from their land.

Cannot allow lesseee to defend based on obligations to other lessors-Difference in Roys was key factor inshoing bad faith-Ther is a reasonable obligation to seek adminstrative relief.

4. Damages

a. Money Damages

Most states have held that the preferred remedy for breach of any covenant is money damages. The amount of money damages for failing to protect against drainage, however, is not unanimously decided.

Some states make it the amount of royalty which would have been paid on the oil which was drained away. Others, however, say the damages should be the royalties on what the off-set wells would have produced if they were drilled. Since the off-set well would almost invariably produce more than just what was drained, this would be a higher measure of damages.

If this second option is chosen, it seems that the lessor has the ability to get double compensation.

They get the royalty on the unproduced oil, but hey still have the oil in the ground. This does not seem right.

Notice that if the damages are royalties, the lessee may be better off being sued than incurring the capital investment of drilling a well.

B. Partial Cancellation

If the drainage is still ocurring, the lessor will probably seek lease cancellation. Courts will award such cancellation, but only to the depths being drained. For example, if there is a strata being drained at 1000 feet and another strata not being drained at 5000 feet, a court will only cancel the lease down to 1000 feet.

Courts are reluctant to cancel leases because it smacks of a taking. The most common remedy is a conditional cancellation - a decree that the lessee must act within a certain time or else lose the undrilled acreage.

C. Implied Covenant to Drill (Duty to Explore-Duty to Develop)

There are two distinct covenants under the implied covenant to drill: the duty to explore and the duty to develop. Both of these covenants can apply both laterally across the land and vertically to different depths.

1. Implied Covenant to Develop

This covenant obligates the lessee to drill at least as many wells and produce therefrom as would a reasonable and prudent operator. Basically, a lessee cannot drill one well on a large tract, and then sit back and do nothing and expect to maintain the lease.

a. Background

Why do courts imply this covenant? All courts agree that such a duty exists, but they do not agree on a rationale. Some claim that the covenant exists to protect lessor's by ensuring they are paid royalties now (while they are alive). Others claim its purpose is to encourage development of proven oil reserves.

What is really at issue here is the timing of the development. The oil company will drill at some point if reserves are known. But, the lessor perceives a reasonable time differently from the lessee. The lessor wants drilling now, so he can collect royalties himself. The lessee can afford to wait. It is looking at a world-wide plan of development. By and large, courts tend to look at this timing issue from the viewpoint of the lessor and long delays are viewed as unreasonble.

b. Elements of Breach

The lessor has three elements of proof for breach of this covenant: (1) unreasonable delay in drilling wells in a proven field; (2) one or more additional wells could have been drilled with reasonable expectation of profit; and (3) lessor gave lessee notice of the breach.

i. Unreasonable delay

When looking at this issue from the lessor's viewpoint, as the courts usually do, this is not a big issue. Most delays run many years. What is unreasonable is a question of fact.

ii. Reasonable expectation of profit

The lessor frequently finds this element the hardest to prove. The profit here is not the same as the profit needed for a well to be producing in paying quantities; the well here must be one that "pays out" - recoups the capital investment.

a) Some commentators suggest that perhaps the lessor should have to take this further and show that a reasonably prudent operator would make this investment--i.e., that the well will not only pay out, but will do so quickly enough for a reasonably prudent operator to take the risk.

b) Sufficient evidence - Texas courts generally hold that showing another prospective lessee

would drill is not enough. That particular lessee may be an idiot.The lessor has the greatest likelihood of success if he can show that a proven reservoir extends further than the drilling site and there are potential drill sites over the reservoir that have not been drilled on.

Notice that his requirement is very difficult to establish because if a well would be profitable, the lessee would typically have drilled it.

iii. Notice and demand

Most courts require the lessor to give notice to the lessee of the breach and allow some time for remedial action. However, some courts have found that if there is no current plan of further development, then there is no reason to allow the lessee to hold on to the leased acreage. Notice is irrelevant.

c. Superior Oil Co. v. Devon Corp.

Usually this covenant is asserted affirmatively by the lessor against the lessee. Here, however, the covenant was asserted as a defense in an action to try title by the lessee against the lessor.

The lessor had leased to Superior. The lessee drilled and got oil, but the productive area was very small. The lessee then joined into an area where there was unitized production on adjacent ranches. That is all the lessee did for this lease.

15 years later, the owners of the ranch purported to lease the area outside of the unitized area to Christianson. The Superior found out about this and sued. The lessor and Christianson asserted breach of the duty of reasonable development by the lessee as a defense. Lessor claimed that the lease was terminated as to all of the ranch but the small area of production. Further, lessor claimed that this termination occured before the lease to Christianson.

The court held that the lessor had failed to give

notice of the breach and demand for correction, so the lease was not cancelled.

d. Protective clauses for lessor

Because it is so difficult for the lessor to establish breach of the covenant of further development, the lessor might try to include one or more of these protective clauses which were discussed above.

i. Pugh clause

If part of the leased premises is pooled with adjacent land, then the lease is maintained only as to the pooled acreage.

ii. Retained acreage clause

A well maintains a lease only as to the specified number of acres per well at the end of the primary term.

iii. Continuous development clause

Similar to retained acreage clause; requires the lessee to continue drilling every so many days until all the drill sites are used up; otherwise, the lease terminates as to the unused acreage.

e. Remedies - four possibilities

i. Interest on the unpaid royalties, or the present value of future royalties. However, it is difficult to prove value of production not obtained.

ii. Unpaid royalties. What the lessor would have gotten had the correct number of wells been drilled. However, lessor still has the oil.

iii. Decree by court to start drilling additional wells or lose the lease. This is done in TEXAS.

iv. Cancellation of the lease. Most lessors prefer this. However, this could be a taking.

2. Implied Covenant to More Fully Explore

Back around the turn of the century, the lessee could not do anything at all on a lease. Accordingly, courts began to imply a covenant for drilling at lease a test well. Todal, however, this covenant is largely unnecessary because a set primary term is used which terminates a lease if no drilling has occurred.

However, the implied covenant still has some import. For example, assume that a lessor leases 10,000 acres to Arco. Arco drills one producing well, but no others. He argues that the reservoir is just barely under your land and no other wells are needed to develop it. What about the rest of your land? There could be other reservoirs. In this situation there is an implied covenant to more fully explore.

a. Elements

Under this covenant, you need only show that the lessee has acted unreasonably. It is not necessary to show that a profitable well will be found because not all exploratory wells are profitable. You need only show that a reasonable operator would drill an exploratory well.

Factors which might be considered in determining if a lessee has acted reasonably might include the following.

- time since last drilling- size of tract and number of existing wells- willingness of other parties to drill- geological data- market prices of oil and gas

b. Profitability standard

In both Texas and Oklahoma, the courts have said that profitability should be an element of proof under this covenant. However, this is really no different than what other states have said. Other states have said that the lessee must only act reasonably. But a reasonable operator would only drill if there was a better than 50% chance of making a profit.

c. Protective clauses

Again, the protective lease clauses discussed above can avoid any problems with this covenant.

D. The Implied Covenant to Market

Clause #3 on the form lease states that the royalties to be paid by the lessee are based on the market price for gas sold off the premises and on the contract price for gas sold on the premises. The lessor, however, is basically without say as to how the gas is marketed. For sales on premises and for off premises sales in states which calculate market price based on the off premise contract price, the lessor is totally at the mercy of the lessee.

Accordingly, the lessee is regulated by the implied covenant to market gas in good faith and with due diligence. Litigation arises where the lessor alleges that the lessee could have obtained a higher price for the gas.

1. Background on gas regulation and deregulation

a. Regulation

In 1954, under the Natural Gas Act, the Federal Power Commission began regulating the sale price for gas sold interstate. Intrastate sales were not subject to regulation, and the prices were much higher. Thus, there evolved a dual market for gas. A big price disparity erupted.

The 1978 Natural Gas Policy Act responded to the price crisis and subjected all gas to price regulations, with 26 different categories of prices. Finally, in 1985, most of these categories were de-regulated.

b. Current prices

Now, some gas companies are tied to old, long term contract where the price was low while also being involved in newer contracts where the price is higher. The current market value of gas has declined somewhat, but is still much higher than the old regulated prices.

To try to help smooth this problem, the Federal Energy

Commission issued order 451 that would allow producers to renegotiate the price of old interstate contracts with a proviso that if the producer asks to do this, the purchaser may condition this on a renegotiation of a more recent, high price contract.

This order places lessees, as suppliers of gas, in a jam. They want to renegotiate the low dollar leases but the lessors with high dollar leases wont let them because their royalties will go down. This was the situation faced in the case below.

c. Amoco Production Co. v. First Baptist Church of Pyote

In the late 1960's, Amoco had a gas well, and entered into a contract to sell gas to Pioneer at 17/Mcf (very low price). A few years later, Amoco and several others pooled their leases to form a second gas drilling unit. P's lease was pooled into this unit.

Church claimed breach of the covenant when it used gas attributable to the lessor's land to get a benfit for itself that chruch didn't shre in.From the new pooled unit, gas was sold. Tw intrastate purchasers, Lone Star and Delhi offered $1.95/Mcf; one interstate purchaser, Natural Gas Pipeline Co. offered 50/Mcf. Amoco instead chose to sell to Pioneer, and offered to sell at 70/Mcf if Pioneer would change the old contract price from 17 to 70 also. Pioneer agreed.

P sued alleging breach of the implied covenant to market natural gas in good faith and won.

Q: Should ct apply different standards when assesing breaches in mkting covenant? Ultimately you as lessee cabt use other lessors as a defense for not doing ehat youwould have done for this tract if you owned it.

2. RequirementsThere are essentially two elements to a breach of this covenant. In other words, there are two ways in which the lessee could fail to act as a reasonably prudent operator.

a. Reasonable price

The lessee must get a reasonable price. What this is, however, is uncertain.

It is unlikely that a court will find liability just because a lessee uses business judgment in turning down a higher priced contract for a lower priced one. There are more factors than just price in agreeing on a contract. For example, the lessee might also consider the length of the contract and provisions for price escalation, etc...

In one sense, Amoco was in the same kind of bind here as was present in Amoco v. Alexander (two lessors, up dip and down dip in water drive reservoir; claim of breach of duty to prevent drainage). Whichever way Amoco goes here, one lessor wll be upset. If Amoco had refused the Pioneer deal, the original lessor would have been upset. The court held it could not act with regard ti its other obligations when dealing with one lessor.

One situation which is a badge of acting unreasonably is when the lessee sells to a sister company. For example, if Exxon Production sold to Exxon Refining there would be a presumption the price is unfair. Here, courts are willing to shift the burden of proof.

b. Diligence

Usually, a lessor invokes this covenant when dissatisfied with the price received for the gas. However, there is a second aspect to this covenant - the duty to use diligence in getting a pipeline contract in the first place.

This is especially important in states like Oklahoma, who provide that a well capable of producing gas will hold the lease in the secondary term even though there is no actual production. In a state like that, a lessee may sit on a gas well and maintain the lease indefinitely. Courts have held in this context that there is an implied duty to market the gas diligently.

If the lessee is paying shut-in royalties, it is arguable that he has no duty to market. But, this is not very persuasive, especially where there is no time

limit on how long the well can be shut-in. This just is not the purpose of the shut-in royalty.

3. Take-or-pay Settlements

If as part of a take-or-pay settlement, the lessee agreed to reduce the price of future deliveries, it seems that the lessor would have a very good argument under this covenant for sharing in the settlement amount.

4. Effects of division orders

Recall that a division order telling a purchaser of natural gas how much royalty to send to the lessor can estop the lessor from making any challenges to the market price.

In Cabot Corp. v. Brown, the court suggests that a division order has the same effect on the lessor's claim for breach of the covenant to market. That is, acceptance of payment via a division order may estop the lessor from asserting that the price is unreasonable. This case had some peculiar facts which might make this not the rule, but it seems likely to be so, at least in Texas.

5. Remedies

Because of the variety of circumstances and theories that might be involved in an application of this implied covenant, there are no general rules as to available remedies. There are several possibilities.

a. Damages are recoverable as an exclusive or preferred remedy.

b. Damages may be recovered concurrently with cancellation.

c. Cancellation is a favored remedy.

d. Cancellation may be granted as to the entire leased premises or of a part thereof.

e. Cancellation may be awarded as a conditional decree under which the lessee would have a prescribed time within which to perform or suffer cancellation.

*Final Catch-All Covenant-"Operate Properly"

Blowout injures res. instead of neglgence suit, sue for this breach.New technology being used extraordinarily welll, lessee does nothing. Or Risky new technology is used in a destructive manner.

IV. Leases on Public Lands

A. Federal Lands

The federal government owns more land than everyone else put together. Further, it owns most off shore rights.

There are three major differences between a lease with a private party and one with the federal government - the manner of acquisition, the environmental concerns, and the resulting entitlement.

1. Manner of Acquisition

The federal government had a policy which encouraged people to develop land to the west in its early years for obvious reasons. Much land that was homesteaded, however, only gave settlers the surface rights. The mineral fee was retained by the federal government. Even though subsequent measures have given many mineral fees to the surface owners, the federal government has tremendous amounts of land to lease.

For on-shore lands, early on there were three primary methods to acquire a lease.

a. Over-the-counter transaction

In situations where the land had never been previously leased and was not suspected of having mineral value, you simply went to the land office and payed a nominal fee. This gave you a lease with a 10 year primary term and a 1/8 royalty.

b. The Lottery

For land which was previously leased but on which there was no production, you filed your name with the land office and there was a drawing to see who got the

lease.

c. Competetive bidding

For land known to have some productive value, there was competetive bidding for the lease. The bidding was typically in the amount of bonus being offered.

Because too many oil companies were getting burned in the lottery, FOOGLRA was passed. Now essentially all federal on-shore lands are leased by competetive bidding. Resulting leases usually have a five year primary term and a 1/8 royalty.

2. Environmental Concerns

Although there are a few environmental provisions in FOOGLRA, an important environmental check on federal on-shore leases is the National Environmental Policy Act (NEPA). Under NEPA, to drill a well there must be a study on the environmental effect performed. This can be either an environmental assessment (EA) or a much more expensive environmental impact statement (EIS).

A debated issue is when an EIS is needed and when the cheaper EA will suffice. Clearly if an EA does not result in a Finding of No Significant Impact (FONSI), then a EIS is required. But when else?

a. Exploratory wells

The Department of Interior has determined that NEPA does not apply to wildcat wells. Accordingly, no environmental study is needed to drill an exploratory well.

b. Developmental wells

i. Leases with NSO

If a lease has a No Surface Occupancy clause, the lessor is prohibited from doing anything on the surface without obtaining an environmental review. Accordingly, it is widely accepted that if a lease has a NSO then only an EA resulting in a FONSI is needed before the lease is executed.

ii. Leases without NSO

If a lease has no NSO (no-site-restriction-lease), then courts are split on whether or not an EA will suffice or if a full EIS is needed.

c. EIS subsequent to leasing

If an EIS was not done at the time of leasing, when, if ever, is one needed? There are two views.

i. One view is that you need an EIS as soon as you apply for a developmental well drilling permit. There is a presumption that one is needed and it is up to the oil company to prove otherwise.

ii. A second view is that it should be viewed on a case by case basis. One developmental well is a far different animal from field-wide development. from a procedural standpoint, this approach would be very tough to administer.

3. Resulting entitlement

Even though a federal lease looks like any other lease, they are viewed as granting an entitlement. They do not terminate automatically. There must always be a termination hearing, the giving of notice, and an opportunity for the lessee to cure.

4. Off-shore leases

The doctrine of a territorial sea provides that a nations boundary extends off-shore for twelve miles. In California v. U.S., it was decided that these territorial seas belong to the federal government and not the states. Subsequently, however, Congress passed the Submerged Lands Act which in essence gave the territorial seas to the states.

In 1945, the U.S. decided that it owned rights to submerged lands extending all the way to the continental shelf. So for submerged lands further than twelve miles out extending to the end of the continental shelf, the federal government owns the mineral rights.

Off-shore leasing by the federal government is now controlled by the Outer Continental Shelf Leasing Act. There are four sections to the act.

a. There must be a five year plan before a lease is granted which considers the environmental impact, the national energy needs, and other possible uses of the land.

b. All leases are offered via competetive bidding.

c. Leases have an exploration period.

d. Leases have a developmental period.

In the end, off-shore leases are very similar to on-shore leases except they have far more environmental consideration.

B. State Lands

The leasing of state lands in Texas is very important. The state has vasts areas of land because of The Submerged Land Act and because of its size. There are essentially two types of leases in which the state is a landlord in - lands it owns in fee and Relinquishment Act land.

1. Lands owned in fee

Much of the land Texas owns is owned outright. For example, off-shore lands, parks and wildlife areas, universities, etc... On all of these lands, if a lease is given it is done so through competetive bidding. Typically, the bid is on the bonus. But in a proven area it might be on the royalty.

2. Texas Relinquishment Act Land

Under Spanish law, the sovereign retained title to all minerals in all lands granted out to private persons. The Republic and later the State of Texas had the same rule, which is exactly opposite from the common law rule.

In the Texas Constitution of 1866, an express provision provided that the mineral rights retained by the State were released to the owners of the overlying soil. In the

Constitutions of 1869 and 1876 there were similar provisions; however, these were held to apply only retrospectively to lands already conveyed, and not to prospective purchases.

In 1895, the State again began retaining mineral ownership and in 1910, Texas began exploring for O&G to the irritation of many farmers.

In 1919, the Texas Legislature enacted the Relinquishment Act, whereby the State gave away 15/16 of all mineral rights to the surface owners. The courts said that the act was not a give away, but really authorized the surface owners to be agents for the state in executing O&G leases.

The problem with this ruling is that surface owners do not own the mineral rights. Accordingly, they can not convet them away. However, the surface owner is entitled to share in 1/2 of the bonus, delay rentals, royalties, and other economic benefits provided by the lease. Thus, if a lease is in effect at the time of conveyance of Relinquishment Act land, the surface owner can reserve some of the rights due him under the lease.

For leases entered after 1988, the landowner is a fudiciary of the state under a new statute.

V. Interests in Oil and Gas

Since the owner of a tract of land in Texas is deemed to have fee simple title to all minerals, including oil and gas, which underlie the surface, it follows that he can convey to others property rights in those minerals. These carved-out property rights in the underlying oil and gas are usually of two basic types: fee simple interests as conveyed through a deed or a lease, and royalty interests.

Common Scenario: If A wants to realize on the value of the minerals, he exeutes an oil and gas lease.

1. Transfers to O the executive right of development2.In exchange for two interests in the land

a.Royalty (non-part)b. Possibility of Reverter.

A. Distinguishing Between Mineral Fees and Royalties

1. Mineral Fee Interests

In ownership in place states, like Texas, the owner of land typically owns two estates in fee simple: the surface estate and the mineral estates. These can be split apart via a severance. The instrument for a severance is a deed or, in Texas, a lease.

Notice that you can sever a portion of the mineral fee but retain the executive right. When this is done, you have created a non-participating mineral fee.

Language Used:

Mineral Fee: "1/2 of minerals in, on and under the land"

What if "1/2 of O & G in, on, under the land and produce and saved" (Prod/save is royalty language)

1. Minority (OK,WVa): grant of 1/16 royalty doesn't create a roylaty interst, it creates a mineral fee interest

a.reasoning: grant of profits from land is equivalent to grant of land itself.

2. Loose Language-Altman v. Blake"1/6 in on under and prod and saved"-Then lnguage subtracts rigths normally associatd wit a mineral fee.

argued four cornersCt: No, intial language granted mineral fee.

a. Application of general property principles

Bodcaw Lumber v. Goode - The simplified fact pattern here involved a Seller who conveyed the surface estate to O, and retained the minerals. Seller then did nothing with the minerals. The question was whether O could obtain the rights to the minerals because of Seller's inaction.

i. Abandonment

O might argue that Seller has lost his interest through abandonment. This theory would definitely not work in a jurisdiction like Texas, which

follows ownership in place. An owner of a corporeal or possessory interest in real property cannot lose that interest by mere abandonment.

In nonownership states, like Oklahoma, which hold that the minerals are only owned when possessed, the right is similar to a license. This is a nonpossessory interest, which Seller could abandon. Two elements are needed to show abandonment, however: (i) nonuse; and (ii) intent to abandon.

ii. Adverse possession

O cannot adversely possess the mineral estate simply by occupying the surface. Seller has no cause of action against O for O's occupation of the surface estate, so the statute of limitations has not started running for adverse possession. O must actually adversely possess the mineral estate itself--i.e., drill, etc. About the only time this argument is seen anymore is in pooling cases, but even there it has not worked.

iii. Dormant Mineral Interest Acts

Since these common law doctrines do not work to remove an abandoned owner from his mineral estate, many states have enacted acts which do so statutorily.

b. Leases as fee simple determinable

The theory of the oil and gas is that it is really a fee simple determinable, because the language of the lease allows for continuation as long as oil and gas are produced. This is the classic language of the fee simple determinable.

c. Terminable Fees

Suppose that a fee simple owner wants to sell his land but retain the mineral fee in case production is imminent. The buyer agrees but eventually wants the full fee. This can be done by the seller retaining a

terminable fee which expires after a number of years unless there is production and giving the remainder to the buyer.

2. Royalty Interests

Typically, "royalty" is defined as any payment from production that will continue for the life of the lease. There are exceptions to this general definition. There are three different types of royalties.

a. Landowner's royalty

This is the royalty provided for the lessor in the O&G lease. It gives the lessor a fraction (typically 1/8) of gross production.

b. Nonparticipating royalty

Created from deed independent of oil and gas lease

No mineral rights, but get a royalty. If anyone else gets oil, you get 1/16 of gross profits.

An expense-free interest in oil and gas if and when produced. The prefix "nonparticipating" indicates the interest does not share in bonus or delay rentals, nor in the executive right. Such royalty owners typically do not share in shut-in royalties (viewed as a delay rental, however, the lease deems them to be production) or production payments (received in leiu of a bonus). However, they probably would share minimum royalties which by definition are not production.

These are commonly reserved by a landowner who transfers land to another; the grantor will reserve a portion of the royalty. There are two different ways of determining the amount of such a royalty.

NOTE: Difference between 1/16 non-part royalty and 1/16 Mineral Fee

*Either one holder gets 1/16 of production*1/16 Roy is 1/16 GROSS produciton*1/16 min fee-1/16 production LESS COST of

production.i. Royalty reserved

The grantor may reserve a specific fractional royalty, to come off the top in the lease. If a later lease calls for x royalty, and the grantor had reserved y royalty, then the grantor would get his y royalty, and the lessor would get x-y royalty.

ii. Percent of royalty reserved

The grantor may reserve only a fraction of the royalty reserved in later leases. Thus, if a later lease calls for a 1/8 royalty, and the grantor had reserved 1/2 of royalty, then he will get 1/16 of the gross, and the lessor will get the other 1/16 of gross.

The advantage of this method is that the grantor can can benefit from the grantee's subsequent negotiations. If the lessor is able to bargain for a 1/6 royalty, and the grantor reserved 1/2 of royalty, then he will get 1/12 of gross, instead of 1/16 of gross. Further, the owner of 1/2 of royalty may be able to share in more benefits than an owner of a straight 1/16 royalty.

The nonparticipating royalty runs with the land and does not expire when any existing lease expires, but applies to any lease, past and future. To get this type of royalty, must have once had an interest in the land; otherwise, the royalty cannot attach to the land. Royalties attached to an interest in the lease are overriding royalties, below.

c. Overriding royalty

An overriding royalty is an interest off the top of a particular leases (or wells) production. For example, Smith Oil might have a lease but no capital to drill, so it gives Exxon a 1/16 interest off the top to finance the drilling. The overriding royalty is an interest carved out of the lease, and expires when the lease expires.

A type of interest which is similar to a royalty interest because it is based on production is a Production Payment.

This is very similar to an overriding royalty except it is given to finance a particular item and ceases when that item is paid off. For example, it might be used to finance the bonus typically paid up front to the lessor.

Production Payment

S owns 1000 subject to G's right of 1/2 of royalty. S negotiates with corp and gets 300k bonus plus 1/6 roy on the lease.

Bonus: we'll give you aditional 200K if produciton. Right to adtional 1/32 of prod until = 200K.

S: Its a bonus, I get it allG:Looks like ROy, payment out of produciton jsut like 1/6 is.

Ct: G losses. Was a bonus, way of compensating me for no up front cash on per acer bais.(could be abused, then diff)

Ct: Royalty is something lasting throuhgout the life of the lease.

3. Distinguishing mineral fees from royalty interests

Since a non-participating royalty interest runs with the land, it is often difficult from the wording of a grant to determine if an interest in the mineral fee or a non-participating royalty interest is being granted.

What is granted makes a huge difference. If it is a mineral fee interest, then the holder shares in the lease benefit proportionately. If it is a non-participating royalty interest, then the holder gets his share off of the top.

a. Words of grant

This problem will not arise if lawyers use the proper wording. If a conveyance gives an interest in minerals produced, it is a royalty. If it gives an interest in all minerals, it is a mineral fee.

Problems arise when the words of grant start to give one of these, but then go on to either give or take away rights it normally does not have. Then it is a case by case determination.

4. Effect of Pooling

In Texas, the holder of the executive interest (more later) cannot pool a non-participating royalty owner's interest

without that royalty owner's consent.

For example, assume S and N own neighboring tracts. S leases to Exxon with a 1/8 royalty. Exxon pools 40 acres from S and 40 acres from N to form an 80 acre unit and drills the well on S's half. A, the holder of a 1/16 non-participating royalty interest in S's tract, can insist on 1/16 of the gross production. This leaves S with nothing.

INFERENCE: Acting alone, S cannot dilute that interest, cna't say production of wuell is shared with N so your 1/16 is reduced.

Assume in the above example that the well is drilled on N's half. Since the well is not on S's land, A does not get his whole royalty, but he is still in a winning situation. A can ratify the lease and get half (40 / 80 acres) of his 1/16 share.

London v. MarylandM: 1/16 non-part roy int in west halfL" executes O & G lease on entire 640 acresStandard PC and "anti-cmmunitzation" clause.

i.e. each persn gets production based on prod on his own land

Ct: anticommuntization clasue means merely signing the lease can't pool interests. M still has option to ratify community lease.

L can protect itself by 1)leasing two tracts seperately 2) 2 seperate lessees (reduces chance of pooling) 3_preconditon to pooling (lesse gets prior raitifcation by all NPR's)

Concurrent Ownership

A. Facts: S and B each inherit 1/2 undivided 1/2 interest in Blackacre. S want to lease it now. B wants to wait.

1. Minority: B wins. Mineral produciton = Waste(can't take away part of theland unless they agree)

2.Majority: Pro-Development Co-T wins.

B. How do you deteminerightsof parties?1.Split bonus/Roys2. suppose S leases 1/2 to M, M gets proudction, will have to account to B for one half of the gross profits!

*Should accountig be based on well by well or tract by tract basis.

C. Implied Ratification

*Could give one sibling the "exclusive exec right" attached to her undivided 1/2 interest.

Open Mine DoctrineT to W for life, remainder to D.Neither W or D acting alone can execute on the lease.

Proceeds-TX:Bonus= Slae pirce of fee simple determinableSold part of corpus-R gets it. But can't use it till life T dies, so invest it and life t gets interest.Royalty: Slae price for drop of land. RDelays: Life T

Open Mine Doctrine: If at time of death O & G lease was outstanding-T is said to have opened the mine; by implicatin treated all roys as income. Life T gets em. If intrust 721/2% to Life t.

C. The Executive Right

The executive right is the right to make decisions with respect to the mineral estate. Explore, drill, produce, mkt, and right to transfer power to do so to another. This usually means the execution of oil and gas leases, but can also encompass other actions, such as authorizing seismic exploration. The holder of the executive right may also drill himself.

1. Division of mineral interests

If one person owns all the mineral interests, then this concept of the executive right is not important. But, if the mineral fee is divided among several owners, and some have rights but no control, then the executive interest is important. The most common examples are the non-participating royalty interst holders and the non-

participating mineral fee holders. These interests have no right to execute a lease, and are dependent on the executive holder to do that.

-Executive right canot be severed and sold.

2. Obligations of the Executive

Executive Duties Hypotheticals1. S to G.(s wants to reserve an interest in the minerals)

a. S reserves a terminable 1/16 roy for five years.Duty to execute w/in 5?

2.S reserves right to 1/2 of Roy.Q: Duty to get highest roy even if it means lower bonus.

3.Conveys to G and reserves 1/2 min fee and no exec rights.G has righ to halfof all benies

Q: has G violated duty if he executes a lease that syas lessee is paying 95K for surface damgea nd bonus of 5 dollars?

Most litigation over executive interests involves the duty of the holder of the executive right to non-executive interests in leasing. For example, assume that R inherited 50 acres subject to a non-participating mineral fee. R needs cash now. Two companies have offered R a lease: Black Dirt offered a lease with $100 per acre bonus and 1/8 royalty, Uvalde offered $25 per acre bonus and a 3/16 royalty. Which lease is R bound, if any, to take? This will depend on the duty that R owes to the non-executive interest. There are three possible standards of conduct.

a. Good faith - not to Defraud

This standard is regarded as too light, because the non-executive is dependent on the executive for benefits. That dependency means that the executive owes the non-executive a higher duty than that owed between ordinary business people. Courts, other than Louisiana, have thus been reluctant to use this standard and it has essentially been abandoned.

b. Utmost fair dealing

The executive must execute the same lease as she would execute if the other interest were not there; must act as a reasonably prudent land owner. This is the

standard imposed by most states.

c. Fiduciary standard

The executive owes the nonexecutive a duty to place the non-executive's interests above the executive's own. This duty seems too high, but at least one Texas court has held that it exists. However, the court could have reached the same end without making this rule and subsequent decisions tap dance around to get back to the prudent land owner duty.

Under any standard, "self-dealing" is viewed as a badge of breach of the duty (contracting with a related party).

C. Other Minerals

A common type of conveyance is of "oil, gas and other minerals." The question of what is included in other minerals is litigated often. There are many approaches taken to answer this question.

1. Approaches

a. Superfolous

One camp says that under this language, the grantee should get only what the instrument specifically conveys. With the above language, the grantee would get only oil and gas. The benefit of this approach, which no court uses is that it is simple, and removes the need to second-guess the parties' intent. But, this approach ignores half the phrase.

*Always suspcious that someone is gettig somethingthey didn't pay for.

b. Ejusdem generis

Under this approach, where there is a specific list of things followed by a general phrase, the general phrase is said to include things like those in the specific list. Here, the "other minerals" would include things like oil and gas.

This is approach still does not fully answer the question. What characteristics are important?

- Hydrocarbons?- Fluid substances?- etc...

Oklahoma takes this approach, but also includes any thing produced with the oil and gas.

c. Ambiguous

Admit the phrase is ambiguous and use extrinsic evidence on a case by case basis. This has obvious administrative drawbacks.

d. Ordinary meaning

Anything ordinarily thought to be a mineral is a mineral. This has been used in Texas since June 8, 1983. It includes the following: oil, gas, uranium, sulphur, gold, silver, deep lignite. It excludes the following: sand, gravel, water, limestone, shallow lignite.

e. Value

Anything with value if extracted is considered to be a mineral. This would include everything from uranium to top soil.

General Intent1. Manner of enjoyment Test

(a) anythings a mineal if its normal or common use reuires extraction

2. Surface destruction test

Two seperate estates. Anything that does not injur the surface estate during extraction is considered to be a mineral.

2. Texas approach

Texas originally followed the surface destruction test. The rationale was that if the parties intentionally created two different estates, they certainly did not intend to let one owner destroy the others property.

This approach essentially ruled out strip mining. Accordingly, uranium and lignite were not considered to be conveyed in a standard oil and gas lease. Today, however, technology has advanced and these minerals can be extracted without strip mining. This led to a rule in Texas that if at any time subsequent to a leases execution a mineral was commonly extracted via strip mining, it was not considered a mineral in a standard oil and gas lease.

This rule was such a pain for title examiners that in June of 1983 the Texas courts changed to the ordinary and natural meaning standard. This change, however, only operates prospectively.

Notice that a person can not convey what he does not own. Accordingly, if I conveyed other minerals to Smith in 1980 and Smith conveyed them to Morales in 1990, I would still own the uranium in Texas.

i.e.1980 S owns X-coveys to G and reservw O & G and minerals1993 S conveys O & G and other mienrals to Brown1993 G sells alnd to ChenChen owns the uranium. in 1980 the surface dest test applied.3. Liability for Surface Damage

Surface damage caused in the extraction of a specifically identified substance is bourne by the lessor. Such damage is considered to have been contempleted at the time of leasing. For unnamed minerals, however, the lessee must bear the costs.

D. Fractional Interests

1. Size of Interest Conveyed or Reserved

Assume Smith owns 1/4 of the mineral fee in blackacre and Morales owns the other 3/4 as well as the surface fee. Smith conveys everything to Jones but reserves "1/2 of the minerals". Has Smith retained 1/2 of what he owned or 1/2 of the entire fee.

Texas uses a straight forward rule of construction. If the conveyance grants an interset in the land described, it is an absolute value 1/2. If the conveyance grants an interest in the land being conveyed, it is 1/2 of the 3/4 owned by Smith. In the above example it would be an absolute 1/2.

2. Duhig Rule

A sticky problem results if a conveyance makes no mention of a third person's outstanding interest. Since the conveyance makes no mention of this, it purports to grant full title to everything but the interest retained by the grantor, thus purporting to grant a larger interest in the land than the grantor has the power to deal with. The rule is set out below in Duhig.

Duhig v. Peavy-Moore Lumber Co.: O conveyed to S reserving 1/2 of the mineral fee. Later, S conveyed to A reserving 1/2 of the mineral fee, but made no mention of O's interest. What did the parties have?

The rule is that S is estopped to reserve in himself an interest that, taking into consideration O's outstanding interest, would leave A with less than the deed purports to give him.

Here, S is estopped to reserve 1/2 of the minerals in himself because O's interest was never mentioned, and the deed purports to give A 1/2 of the minerals. Thus, O has 1/2, S gets nothing, and A has 1/2.

This seems contrary to property law. A could have done a title search. Accordingly, he should be the one to lose out.

Problem: Now the thrid person, B conveys to C thniking he only has the surface (really has 1/2 interest in mins)-made it subject to a half interest by O and A.A argues that reservation clause has gvein her 1/2 interest backTexas: No, can't reserve interest in someone who isn't a grantor.

E. Non-apportionment Rule

Simply stated, the non-apportionment rule states that if a tract of land is subject to an oil and gas lease, and subsequently it is divided, the resulting two owners have no right to share in royalties from wells on the other's portion of he land.

This can be a harsh rule because the lessee is under no obligations to drill on both of the new tracts. The entire tract is one big lease to him.

You can get around this by using an entirety clause in the conveyance. Such a clause would have the effect of the two owners sharing all royalties, probably on a surface acreage basis. This would be the same result if the lease were entered after the severance in a community lease.

Another possible remedy would be to muscle-in through forced pooling. However, this would only work if your tract were too small to form its own drilling unit.

Problem: What if originalplot were only 40 acres. Only 1 well.A:Rule is still the same.

VI. Contracts and Transfers by the Lessee

A. Lease Assignments

Leases may be assigned, and commonly are because they are often obtained by land men who obtain them with the intention of assigning them in the first place, or by companies with inadequate funds to dvelop or a desire to share the risks. The assignor typically retains an overriding royalty in the transferred acreage. This royalty will expire when the lease expires. (Contrast: nonparticipating royalty which runs with the land).

1. Duties owed to lessors

As operators with the esecutive right, assignees owe the same duties to the lessor as the lessee (assignor) did. They include all impied covenants and the overall duty to act as a reasonably prudent operator.

2. Duties owed to assignors (lessees)

The question here is what duty is owed by the assignee of a lease, who holds the executive interest, to the assignor, the party who leased from the landowner. Specifically, is there a duty to maintain the lease and enable the assignor to continue to receive his overriding royalty?

In Brannan v. Sohio Petroleum, S is a lease broker, never intending to drill the lands himself. He leases from O, O retains 1/8 royalty, then S assigns to A, retaining a 1/16 of 7/8 (7/128) overriding royalty. A now has a 105/128

interest in gross excluding both S and O's interests. A knows that if he drills before expiration of the primary term, he must pay S a chunk of the proceeds. But, if A lets the lease expire, and re-leases directly from O, then A can keep those proceeds himself.

Such a lease is called a top lease. A lease to begin to run after expiration of existing lease - called a bottom lease.

S argued that there was a breach of a fiduciary duty so the overriding royalty should continue in the new lease. But the court held that there was no fiduciary duty owed to an assignor. S could have protected himself with appropriate language in the assignment. It is just a straight business relationship, so just the assignee only owes a duty of simple good faith.

Top LeasingEffort to begin a lease immediately upon the terminationof another lease. Void: Second lease violates the rule against perpetuities.

3. Covenants and Assignors

There is some controversy as to whether or not an assignee owes the same implied covenants to an assignor as he does to a lessor. Typically, it does not matter because the lessor will watch out for the assignor's interests. But the following case illustrates a situation where it does.

In Cook v. El Paso Natural Gas Co., Cook was the original lessor of the land from the U.S. He assigned the lease El Paso. El Paso had a federal lease on adjoining land and drilled a well there. The drained from under land where P had retained a 5% overriding royalty. The lessor, U.S., was not concerned with drainage because it owned both tracts.

P sued for breach of implied covenant in the O&G lease to protect aganst drainage and won. The court said that the implied covenant applied in this case.

Smith says the court was wrong. They have really created a new implied covenant - not properly applied the existing one.

4. Compared with Duty owed non-participating royalty holder

This no duty crap does not work if he party injured is a non-participating royalty holder. Since these holders are typically unsophisticated individuals rather han oil and gas companies, courts are not as willing to look out for them.

B. Farmouts

There are several contexts in which all or part of an oil and gas lease may be assigned. One of the most common is the farmout, an agreement under which one who owns an oil and gas lease (the farmor) assigns an interest in it to another person (the farmee) in exchange for testing and drilling operations.

Historically, farmouts have taken a fairly common form. The farmee will receive an assignment of the entire working interest in one drilling unit of a larger leased tract, subject to an overriding royalty in the farmor which is convertible into a 50% working interest upon payout.

The assignment of the drilling unit lease is consideration in a unilateral contract where the farmee has the option to accept the contract by drilling. The farmor gets valuable geological information as well as whatever else he may negotiate such as an overriding royalty with a conversion feature. The farmee gets the drilling unit as well as what ever else he may negotiate such as an interest in the rest of the leased land.

C. Joint Operating Agreements

As previously discussed under pooling, when two or more parties have an interest in the same drilling unit, they must come up with a Joint Operating Agreement to govern their relationship.

1. What does it do?

The JOA spells out how production and costs will be divided. Also, it specifies which party will be the operator.

2. Not a partnership

Typically, a JOA will spell out in its text that it does not create a general partnership. This is done both to limit the liability of the non-operators and to prevent the operator from owing the others a fiduciary duty.

a. Limited liability

The JOA will purport that each party is severally liable only for its share of authorized costs. Only the operator can be sued for any tort damages.

i. Texas

In Berchelmann v. Western Co., Texita was the operator in a JOA. Texita incurred debts in the operations, then went bankrupt. The creditors went after the non-operators. Their argument was that this was really a partnership.

The court said no, that the operating agreement was effective to do what it purported to do - i.e., limit the liability of the non-operators. Thus, the non-operators were only liable for their proportionate share of the expenses, and then only to the extent that they have not already paid this to the operator.

ii. Other States

Not all states are as lenient as Texas. Some other states say what walks like a duck is a duck.

iii. Torts

In a tort context, a court is more likely to impose joint and several liability, even in Texas.

B. Fiduciary duty

It is clear that in some circumstances the operator is a fiduciary of the others. For example, he must invest joint funds. However, it seems that this arises from the relationship as it is, not from it being a partnership.