Oil & Gas Contracts

Copyright © 1996 by Lewis G. Mosburg, Jr.

An Introduction to


By Lewis G. Mosburg, Jr.

Copyright © 1994, 1996 by Lewis G. Mosburg, Jr. All Rights Reserved.

Part One: Introductory Concepts; Farmout Agreements


Many alternatives are available to the oil and gas company in the development of its lease acreage. Drilling "heads up" -- bearing all the cost and risk of the drilling, and solely reaping any rewards -- is always a possibility. However, for years the trend in the industry has been a multi-company development of acreage.

If multi-company development is in order, the following are possible arrangements:

1. Support

2. Farmouts

3. Joint Operations

4. Farmout (Drilling) Options

5. Seismic Options

6. Exploration Agreements.

Often, these arrangements are used in combination: a company may farm out plus offer support toward the drilling of a well, or a company accepting a farmout for initial drilling may then join with the farmor in joint operations for the development of the balance of the acreage. Also, any of the arrangements outlined above may be used in combination with the forming of an "area of mutual interest" ("AMI"), under which all of the parties to the contract will have the right to share in additional acreage acquired by any of the other parties.

This paper will focus on the contracts utilized in two of the arrangements just mentioned: farmout agreements and joint operating agreements (specifically, the "model" form of joint operating agreement adopted by the American Association of Petroleum Landmen).

This month's discussion will focus on the Farmout Agreement. Next month, we will overview domestic Joint Operating Agreements.


Nature of the Farmout. Farmouts are utilized when one company has acreage which another company wishes to acquire through drilling. The company with the acreage position has determined that it is not intelligent for it personally to undertake the costs and risk of developing the acreage (at least initially), but does not wish to see its leases expire. The company willing to undertake the drilling has a prospect idea which it wishes to develop, but does not control the acreage. Under the farmout, the first company (the "farmor") agrees to assign acreage to the second company (the "farmee") in return for the second company performing specified drilling and testing obligations, with the first company also reserving an interest in the acreage assigned and in the production from the wells drilled by the second company.

"Farming out" makes sense if a company is unable to develop expiring acreage due to budgetary constraints or it wishes to reduce or eliminate risk and improve economics as a percentage of investment and is willing to accept in return a reduced acreage position (and thus a reduction in potential aggregate return).

"Farming in" makes sense if a company's budget can stand the costs of drilling and the company is willing to accept greater costs and risks to gain or increase its acreage position in the area and thus increase its potential aggregate return.

From the standpoint of the farmee, the reason for entering into the farmout agreement is simple: it wishes to acquire an interest in acreage controlled by the farmor. Since, historically, most members of the oil and gas industry have been unwilling to sell potentially valuable undeveloped leaseholds for cash,1 and since earning by drilling has tax advantages from the standpoint of the acquiring party,2 the farmout represents the most effective (if not in most instances the only) method of acquiring such acreage.

From the standpoint of the farmor, the motivation for entering into the agreement may be more complicated. Its objectives may include maintaining its leases; having the area evaluated and tested; or securing a cost and risk free interest in production. All of these motivations may be present in a given transaction to a greater or lesser degree. However, how the farmout should be structured from the standpoint of the farmor will vary, based upon which of the objectives is of primary importance.

Areas of Negotiation -- In General. In negotiating the farmout, the parties will primarily be concerned with three basic issues: the extent of the farmor's maximum commitment (the "subject matter" determination), what the farmee must do to earn an interest in the acreage (the "earning requirements"), and what will be assigned to the farmee if these earning requirements are satisfied and what the farmor will reserve ("interests assigned and reserved").

There are numerous other topics that will be covered in the written farmout contract. However, these three subjects are the key to insuring that there has been a "meeting of the minds" between the farmor and the farmee.

-- Subject Matter of the Farmout. Frequently, the farmout agreement establishes "mini-maxi" parameters: the farmee must satisfy certain minimum requirements if it is to earn anything under the farmout but its earning may be increased up to a specified maximum interest if it performs more than the "bare minimum" earning requirements. Thus, the farmor must determine the maximum amount of acreage which it is willing to commit to the farmout, assuming maximum performance by the farmee (the "farmout area" designation), and the maximum depth to which it is willing to commit this acreage to the farmout (any "farmout depth" limitations).

Obviously, the more the farmor is willing to commit to the deal, the easier the farmout is to sell and the more favorable the terms to the farmor. However, since the farmor will be reducing its acreage position within the farmout area, it may prefer to farm out a limited amount of acreage on less favorable terms to itself in return for retaining its full position in the balance of the acreage it owns in the general area.3 Also, while as discussed below the farmee's earning will normally be limited to the depths to which it drills in its earning wells, the farmor may have certain formations which it wishes under any and all circumstances to retain for its own subsequent development.

Once the parties have agreed upon the maximum amount of acreage to be committed to the farmout, and the maximum depth to which such acreage will be committed, both must also agree as to what to do if additional leases are subsequently acquired within the farmout area by either party to the arrangement. It may be that there is no "open" (unleased) acreage within the farmout area, in which case the point is moot. (Industry practice is to agree that the parties will have the right to share in any extensions or renewals of the leases committed to the farmout.) However, if there is open acreage, or other companies which are not parties to the farmout own leases within the farmout area, the farmor and the farmee must decide whether or not to include an area of mutual interest provision in the agreement.

Absent an express "AMI" provision, there is no implied right to share in additional leases acquired by the other party, even though those leases lie within a "contract area" covered by an existing contract between the acquiring party and another industry member. Thus, if there is to be a right to share in subsequent lease acquisitions, this must be spelled out in the contract.

A final determination concerning the leases to be assigned is whether the farmee will earn its interest simply by satisfying the earning requirements or whether the farmor expects a cash consideration to be paid in addition to the performance of the drilling and testing obligations. In a typical farmout by a major oil company, there will be no cash changing hands. However, if the farmor is an independent, it is quite common that the farmee is required to make a cash payment to the farmor to reimburse it for the costs of working up the prospect and to cover its costs of lease acquisition.

-- Earning Requirements --- Wells to be Drilled. The farmout agreement must spell out the number of wells to be drilled as "earning wells" by the farmee, the amount of acreage earned by the drilling of each such well, and whether the drilling of one or more of the wells is mandatory (a "required" well) or optional.

If the farmout area is limited to a single drilling and spacing unit, there is but one well to be drilled; whether the drilling of that well is merely a condition of earning (an "optional" well) or is a contractual obligation (a "mandatory" well) is simply a matter for negotiation.

If the farmout area covers multiple possible well locations, it is quite common that the farmee must drill several wells to earn an interest throughout the entire farmout area. Quite commonly, the drilling of the first well will be mandatory and such drilling will earn the farmee an interest in the drilling and spacing unit upon which that well is located and -- in the case of an exploratory farmout -- in certain offsetting drilling and spacing units. If the farmee wishes to earn an interest in the balance of the farmout area, it may do so by drilling additional earning wells, with such additional drilling normally being optional with the farmee.

If the farmout area is not too broad, the agreement will normally provide for the drilling of a specified number of additional optional earning wells. For broad farmout areas, a "continuous drilling" provision may be included, under which the farmee may continue to earn additional acreage so long as it commences a new earning well within a specified number of days following the completion or abandonment of the last earning well. Also, if the farmor is committing its leases over a very broad farmout area, there may be more than one mandatory earning well.

A careful study of the farmout agreement may show that some wells labeled as "mandatory" are in fact only optional conditions of earning. Thus, an early article in the contract describing such a "mandatory" well may be followed by a subsequent "performance" provision stating that the only penalty for failing to drill the "mandatory" well is a loss of the acreage which otherwise would have been assigned. It is also important for a farmor to realize that most smaller farmees assume that all earning wells are simply conditions of earning, no matter how the farmout agreement is worded. If the farmor wishes to insure that the farmee considers itself contractually committed to the drilling of the mandatory earning wells, it may wish to insert a "non-drilling payment" provision in the agreement specifying an agreed monetary compensation which shall be paid by the farmee to the farmor if the mandatory earning wells are not drilled.

--- "Contract Depth" Provisions. In some farmouts, establishing production at any depth will satisfy the drilling requirement. Normally, however, the farmor wishes to insure that, at a minimum, the farmee drills deep enough to establish the presence (or non-existence) of a given formation and that formation's productive capacity before a well will qualify as an earning well. The provisions of the farmout agreement that establish this minimum depth to which the farmee must drill if the well is to qualify as an earning well are referred to as the "contract depth" provisions.

Since the farmee does not wish to be obligated to drill to an unconscionable depth in order to meet its contractual obligations, the contract depth is normally defined as the lesser of a fixed depth or the depth sufficient to test a specified formation.

During the course of drilling the earning well(s), the farmee may encounter conditions which make it impossible, foolhardy or unwise to continue the drilling to the contract depth. Both to eliminate any "breach of contract" exposure on mandatory wells, and to provide for some minimal earning on earning wells which cannot reach the contract depth, the farmout agreement customarily excuses the farmee from drilling to the contract depth if it encounters "granite or other impenetrable substances or other conditions in the hole rendering further drilling impractical."

The fact that a farmee is excused from drilling to the contract depth does not mean that it still earns its full (or any) rights from that earning well. In some instances, the "excuse" clause merely avoids liability for failing to comply with the depth requirement on a mandatory well. In other instances, there is a limited earning (e.g., to the depth drilled/deepest productive formation penetrated, but in the earning-well drilling and spacing unit only). However, most commonly in today's farmout agreements, the farmee will earn only if it drills, and may be required to drill, a "substitute well" which does reach the contract depth.

--- "Productive to Earn." In some parts of the country, farmout agreements are structured on a "drill to earn" basis: if the earning well satisfies the depth and testing requirements of the contract, the farmee will be assigned its interest in the farmout leases even though the earning well is non-productive. Today's farmouts, however, are more commonly "productive to earn": a well does not qualify as an earning well unless it is also productive.

--- Testing and Information Requirements. The farmor often is seeking an evaluation of the farmout area, both to determine whether or not to participate in further development of the farmout area after the earning wells have been completed and to decide whether or not to drill on other leases owned by it outside the farmout area. Thus, the farmout agreement will normally call for specified testing of the well by the farmee through the taking of cuttings and core samples, the running of specified "logs," drillstem testing and the like, and the providing of the resulting information to the farmor.

-- Interests Assigned and Reserved --- "Farmout Depth." The farmee may be assigned his interest in the farmout leases without any depth restrictions. Far more customarily, however, the assignment will be limited to a depth which bears some relationship to the depth actually attained by the earning well(s). This "farmout/earned/assigned depth" provision is normally worded either as "[xx feet below] the depth drilled" or "to the stratigraphic equivalent of the depth drilled" in each earning well.

--- Interests Assigned and Reserved in Production and Acreage. The structure of the farmout as to interests assigned in production and acreage is influenced by both business and tax considerations. To insure the fullest deductibility of intangible drilling and development costs, the majority of farmouts are structured so that the farmee bears 100% of the costs of drilling each earning well and is assigned 100% of the "working interest" (the leasehold operating rights) in the earning-well drilling and spacing unit, with the farmor reserving an overriding royalty during the "payout" period (the period until working interest revenues, net of operating costs, equal the cost of drilling, completing, and equipping the well). Once this payout has occurred, the farmor is given the option to convert its overriding royalty interest to an undivided working interest.4

In addition to permitting the farmee to secure maximum deductibility of its intangibles, this "convertible override" approach permits the farmee to receive the lion's share of revenues until payout has limited its cost exposure, but then allows the farmor to share significantly in well revenues.

If as is typical in an exploratory farmout, the farmor has "sweetened" the deal to the farmee by providing that the farmee will also be assigned an interest in certain drilling and spacing units offsetting the earning well, the farmee is normally assigned an undivided working interest in this "boot" acreage with the farmor similarly reserving an undivided working interest in the acreage.

In some instances, the parties may agree to a different sharing of earning-well costs and revenues. The farmor might prefer a "carried interest," in which it may bear some portion of completion and equipping (though not drilling) costs, and in return receive from the date of first production a share of working interest revenues which is not subordinated to farmee payout. The farmor might also reserve a "casing point election," under which it is not required to choose between the convertible override or carried interest approaches until after testing is completed on the earning well. Or there may be a "disproportionate sharing," in which the farmor bears some portion of all earning-well costs but receives a much larger share of working interest revenues which, again, is not subordinated to well payout to the farmee.

Any of the alternate arrangements just suggested would normally result in a disallowance of some portion of the deduction for intangible drilling and development costs under the Internal Revenue Service's "disproportionate allocation" rules. However, if the venture is structured as a "tax partnership" through an election not to be excluded from the provisions of Subchapter K of the Internal Revenue Code, and certain other provisions of Treasury Regulations are satisfied, there is no loss of the deductions for intangibles. Tax partnerships may also be used to avoid issues of an "exchange of property for services" under the federal income tax code.5

Normally, the farmee will not be assigned its interest in the farmout leases until after the earning conditions have been satisfied (the "assign when earned" approach). However, in a "productive to earn" farmout, the farmee may insist upon being assigned its interest when the farmout agreement is entered into (the "present assignment" approach) to avoid any argument that it did not own the "operating rights" as of the date of drilling which are necessary for intangible drilling and development costs to be deductible. A present assignment may also be used to avoid capitalization of delay rentals or as another method of dealing with the "exchange of property for services" issue where the fair market value of the assigned leases is relatively low as of the date the farmout agreement is executed.6

Next month: Joint Operating Agreements.

* * * * *

1 Formerly, an "absolute:" you could not acquire another company's acreage for cash (at least, acreage of the type you would want to acquire). However, under today's economic conditions, a company in "distress" may be willing to dispose of its acreage for lump sum payment.

2 Discussed in the Primer on Oil & Gas Taxation.

3 If the drilling under the farmout proves up the area, this retained acreage can then be developed by the farmor for its own account or farmed out to others (including the farmee under the original farmout) on terms more favorable to the farmor than those of the original farmout - or than those terms would have been even if the reatained acreage had been committed to the original deal.

4 The tax principles involved in this type of structuring will be discussed in the Oil & Gas Taxation Primer.

5 Tax partnerships will also be discussed in the Oil & Gas Primer.

6 Again, see the Oil & Gas Taxation Primer.




Copyright © 1996 by Lewis G. Mosburg, Jr. All Rights Reserved.

Author's Note:

Problems of gas "imbalance" arise when gas is being taken or marketed by working interest owners in ratios which differ from those in which the gas is owned. Such problems – and their attempted resolution through instruments referred to as "gas

balancing agreements" – are not new. However, the collapse of the gas market in the 1980s demonstrated to the industry just how serious these problems were and how simplistic – and incomplete – were prior efforts to remedy the problems.

This Primer will focus on the rights of working interest owners when imbalances arise (or

are threatened) and there is no gas balancing agreement in effect between the parties; the impact of gas imbalance on the payment of royalties; and the nature and use of "gas balancing agreements" to deal with these problems.

Part One: Introduction to Gas Imbalance: How Gas Is Marketed

The market for natural gas – and the methods in which natural gas is marketed – have changed dramatically over the last fifty years. Gas has gone from a product which has little value to one which whose value is high, although not as high as the industry would like. The demand for natural gas has changed from non-existence to hysterical stock-piling to a more balanced approach. And the country is now crisscrossed by a net of pipelines which offer the potential to transport natural gas from anywhere in the United States to anywhere.

Prior to the middle of the 20th Century, there was little demand for natural gas, unless there was a convergence of a need and a source in the same geographical locale. However, with the growth of the interstate pipelines came a related surge in the demand for natural gas.

Three characteristics marked this market:

1. The only available market and method of marketing for the working interest owners were to sell their natural gas to the pipeline purchaser, who as a "merchant" would resell that gas to the local distribution companies ("LDCs") and industrial end users which it served.1 Similarly, the only available source of natural gas for the LDCs and the end users was the pipeline.

2. The seller delivered gas from its fields, which was then transported to the ultimate consumer, even if this required transporting the gas thousands of miles.

3. The working interest owner would commit the gas produced from specified wells, leases, fields or counties to the performance of the contract. However, it would not be required to "warrant" the quantity of gas to be delivered.

Figure One illustrates this method of marketing natural gas, which with limited exceptions, remained the only way in which gas could be sold by a working interest owner until the mid-1980's.2


In the mid-1980s, the Federal Energy Regulatory Commission began taking action which resulted in the breaking of the monopoly of the pipelines as the sole available purchaser of/market for gas for working interest owners and the sole available seller/source of gas for consumers. These actions culminated in orders requiring that services for transportation, etc., be "unbundled" so that working interest owners and consumers could now deal directly with each other, while turning to the pipelines only to provide transportation services.3 In addition, a new player arrived on the scene – the natural gas wholesaler– who, either as agent or as principal, would serve as a "middleman" to put together a "package" of natural gas, matching the needs of the consumer with the supply which could be provide by one, several or many sources of natural gas.4

Figure Two illustrates the increased options available to the producers - and the consumers - of natural gas as a result of the FERC's action.


In addition to giving working interest owners and consumers much greater flexibility in structuring their gas marketing arrangements, the developments of the last ten years have worked a number of other changes in the way in which natural gas is marketed:

1. The working interest owner now normally commits to deliver a specified volume of natural gas at a specified delivery point, rather than committing specified wells or acreage to the contract, but only up to their capacity to deliver.

2. Most large oil and gas companies have formed their own natural marketing affiliates, to which they sell the majority – and, often, the substantial majority – of their natural gas production.5 This same marketing affiliate may also purchase natural gas from other companies – frequently small producers that lack the expertise, influence and resources effectively to market their own natural gas production – thus serving as "middle men" in dealing with these other working interest owners.

3. Aside from characteristics which purchasers have frequently considered as adding value to a supply of natural gas, such as heating value, quality, and delivery pressure, there are other attributes that are looked at as marking a gas sales proposal as being one of superior attractiveness. These marketing "pluses," which will justify charging a premium for such packages – and may even prove an essential for being able to market the gas to some purchasers – include:

a. Reliability of the promised gas supply: will the seller actually be able to deliver the promised volumes.

b. Length of the commitment. Many consumers are concerned that gas shortages may arise in the future.

c. Flexibility in the area of obligatory and available volumes. A "mini-maxi" arrangement, under which the purchaser agrees to buy a specified minimum quantity of gas during the specified period, with the seller committing to deliver additional volumes upon demand (up to a specified maximum commitment) is a very desirable feature from the standpoint of the purchaser.

In the past, the premiums that lead to a higher price – or avoided price reduction – for a given natural gas "package," such as quality, pressure and heating value, obviously related to the nature of the gas being produced, and seemed clearly a part of the "value" of the related production. Accordingly, that "value" was to be shared with the royalty owner and would otherwise be considered a part of the price for which the gas had been sold.6 However, the premiums being paid for reliability of supply, length of commitment and flexibility in deliveries, could be considered more related to the packaging that was provided by the marketer than an inherent value of the gas being produced. This means that issues will arise as to the price to be used in calculating royalties, severance taxes and cash settlements for gas imbalance.7

* * * * *

Many other basic concepts affect the practicalities of gas imbalancing and gas balancing, including why gas balancing even arises as an issue between working interest owners. These will be the topics of next month's discussion.

Next Month: "Introduction to Gas Imbalance: Setting the Stage with Some General Concepts."

* * * * *

1 Occasionally there would be a "direct" sale (or an attempted direct sale) from working interest owner to ultimate user, if the producing field was located in the vicinity of the purchaser so that the seller could afford to construct the necessary transportation, or, in a few instances, where one or more majors attempted to construct a popeline for some major sales project. However, these instances were relatively uncommon.

2 The pipelines, as owners of the means of transportation of natural gas from the source of production to the point of use, were effectively able to prevent working interest owners and consumers from dealing directly with each other by refusing to agree to transport the gas from point of production to this point of use. In addition, the pipelines normally had enteres into "commodity bill" arrangements (a pipeline version of a "take or pay" contract) with their customers, leaving these consumers unable, economically, to deal with anyone else.

3 As a part of this regulatory strategy, the FERC also excused the pipeline's customers from their "commodity bill" obligations so long as the customer was willing to let the pipeline transport an equivalent volume of gas; the pipelines were not, however, let off the hook from their related "take or pay" obligations to the producers - unless the pipeline agreed to become an "open access" transporter at prices set by the regulators.

4 Also referred to, with certain variances in the role, as a "broker," "marketer" or "packager." By staying on top of who needed gas, and what gas was available, short term and long term, the wholesaler could often provide a higher wellhead price to the working interest owner and a lower purchase price to the consumer.

5 Pipelines, on the other hand, are also established marketing and producing affiliates, and LDC's may also form similar entities.

6 Issues could - and did - arise over higher prices and/or charges for transportation and gathering, compressing and processing. This will be addressed in the Oil & Gas Primer.

7 These issues will be discussed later in this Primer and in the Oil & Gas Lease Primer.