Trent Maxwell

How Do I Examine Title to a Federal Oil & Gas Lease?

For federal oil and gas leases, examination of the title documents is vital for the operator to understand the ownership and identify any title defects or other potential business risks prior to commencing drilling operations.  For a recently issued federal oil and gas lease, examining title is likely to be a straightforward and quick process.  On the other hand, examining title to a federal oil and gas lease issued several decades ago, covering multiple sections, and previously developed, is likely to be a complex and time-consuming process.  In either event, a title examiner must look at several different sources to get a complete picture of chain of title and be able to confirm the term and status of a federal oil and gas lease.  This article provides a summary of the sources necessary to examine title to a federal oil and gas lease.

1.   BLM Records

a. BLM Lease File. The most obvious source of title is the lease file maintained by the Bureau of Land Management (“BLM”).  The lease file contains documents relating to the lease sale, a copy of the lease, rental receipts, lease status notices, any filed assignments, and other documents, such as those relating to communization agreements.  Federal regulations require that an assignment of record title or a transfer of operating rights be filed on prescribed forms and approved by the BLM to be a valid conveyance recognized by the United States.[1]  Federal regulations also require that transfers of overriding royalty interest, production payments, and similar interests to be filed with the BLM,[2] although such assignments are not approved by the BLM.

The examiner should be aware that a lease may have been created by segregation from another lease—for example, by assignment of 100% of record title interest in a portion of the leased lands or by commitment of less than all of the leased lands to a federal unit.  In such instances, it is important to also examine the original lease file from inception until the time that the original lease was segregated into the new lease to understand the complete chain of title and confirm the term and status of the new lease.  For example, there could be an overriding royalty interest or other burden on production in the original lease file that is applicable to the new lease.

BLM lease files are not online and must be reviewed at the relevant BLM office.

b. Online Sources. In addition to reviewing the BLM lease file, there are several online sources that provide useful information and should also be reviewed when examining title to federal oil and gas leases. The first three sources below can be accessed on the website for BLM’s General Land Office, for most states (or links to the relevant state websites can be found on the website), while BLM’s LR2000 system can be accessed at

i. Patents. A patent search should be conducted to determine if any patents have been granted on the lands in question and, if so, to determine if any mineral and other interests were reserved.  In the case of a federal oil and gas lease, oil and gas ownership and rights should have been reserved by the United States.[3]

ii. Historical Index. The historical index for a township provides information in table form regarding all actions and authorizations for a township until a certain date in chronological order. This information includes the serial number, date, and affected lands for each authorization or use. For instance, the historical index provides information regarding land withdrawals, patents, issuance and termination of leases, and rights-of-way.

iii. Plats. The BLM maintains a master title plat in addition to other possible use plats (such as oil and gas, coal, and potash plats, etc.) for each township. These plats indicate which lands are currently owned by the federal government, agency jurisdiction, and rights reserved to the federal government on private land, such as a mineral reservation in a patent. Additionally, plats are useful tools to determine what rights may exist on the lands, such as rights-of-way, fences, land management areas, and other uses, and should include the relevant federal oil and gas lease. As a practice tip, a plat may contain notations on the side of the plat, such as secretarial orders affecting the entire township, that can be easily overlooked when examining the plat.

iv. LR2000. The BLM’s LR2000 system is a highly useful resource that provides reports on BLM authorizations. Of these reports, a geographic index report listing the authorizations for a specific section of land and serial register pages are commonly used by title examiners. Serial register pages are essentially a snapshot of the BLM authorizations, including the relevant federal oil and gas lease, and contain relevant information, such as its status (active, expired, etc.), affected lands, acreage amounts, relevant dates (e.g., the effective date and expiration date), and other useful information, such as if production was achieved and any communitizations involving the federal lease. Additionally, the serial register page indicates the current record title owner and any operating rights owner recognized by the BLM and may contain entries relating to recent assignments that have not yet been included in the lease file.

2.   County Records
County records are another necessary source to examine the complete chain of title and confirm the term and status of a federal oil and gas lease. In most states, filing documents with the BLM does not provide constructive notice. Instead, constructive notice is provided to other parties by recording the instrument in the appropriate county office. Because certain documents must be filed with the BLM (as noted above), this often results in two separate chains of title—one in the federal lease file, and the other in the county records. Frequently, these chains of title do not entirely match each other. This can be problematic if, for instance, the amount of interest assigned in an instrument included in the federal lease file contradicts the interest conveyed in a counterpart county document. Often, however, the two chains of title are useful to explain gaps that appear in the other chain of title, such as missing assignments or mergers, and to understand the intent of parties when their intent may be unclear by reviewing just one of the chains of title.

As noted previously, assignments filed with the BLM must be on prescribed forms. Because of this, parties are limited as to what can be included on these assignments. County documents have the advantage that they do not need to be in a certain form, beyond any statutory or other legal requirements and any requirements for the the document to be recorded in the county, such as signatures being acknowledged by a notary or including a legal description. This flexibility allows parties to include additional provisions in the instrument and to incorporate other documents by reference, such as an unrecorded purchase and sale agreement between the parties (although states vary in their treatment to referenced unrecorded agreements). Additionally, parties can record assignments in the county that are not recognized by the BLM, such as wellbore assignments, term assignments, or assignments containing reversionary rights. Although the BLM does not recognize these types of assignments, these documents are binding between the parties and on third parties who have constructive notice.[4]

3.   Other Records

Finally, it is important to review any relevant states regulatory or commission sources. State regulatory or commission websites vary depending on each state. Records that can be found at these sources may include administrative orders (such as pooling or spacing orders), well files, and production records. These records are an important source to understand the history and status of the lease. For example, the BLM lease file may indicate that a federal oil and gas lease achieved production during its primary term and is held past its primary term by production. In such instances, it is important to review the production records to ensure that there is still sufficient production on the leased lands (or lands communitized or unitized with the leased lands) to continue holding the lease.

In summary, whether the records are straightforward or complex, by reviewing the sources above, a title examiner can be confident that they are obtaining a full picture of the title and status of a federal lease oil and gas lease and can identify any potential pitfalls that exist.

[1] 43 CFR § 3106.4-1.  See e.g., River Gas Corp. v. Pullman, 960 F. Supp. 264, 266 (D. Utah 1997) (“It is well established that a party must receive the approval of the Secretary of the Interior in order for an assignment of a government lease to be valid.”).

[2] 43 CFR § 3106.4-2.

[3] Patents may also be recorded in the county records.  However, the BLM maintains the original copies of patents, while copies in the county were often recorded on patent “forms.”  Due to human error, at times the wrong county form was used and the county copy conflicts with the BLM copy—e.g., the copies may conflict as to what rights were reserved by the United States .  Because of this, the title examiner should rely on the patent copy maintained by the BLM.

[4] Although county documents do not need to be on prescribed forms, it is common to see BLM form assignments recorded in the county records.

White House Announces Regulation of Methane Emissions from Existing Oil and Gas Sources

The White House announced yesterday that the Environmental Protection Agency (EPA) will begin to “immediately” develop “regulations for methane emissions from existing oil and gas sources.” Although no set timeline was provided, the White House stated the EPA “will move as expeditiously as possible to complete this process.” Moreover, next month the EPA “will start a formal process to require companies operating existing sources to provide information to assist in development of comprehensive standards to decrease methane emissions.”

The statement was made in connection with Canadian Prime Minister Justin Trudeau’s visit to the White House on Thursday and was included in a statement issued by President Obama and Prime Minister Trudeau entitled “U.S.-Canada Joint Statement on Climate, Energy, and Artic Leadership.”

This announcement follows the rule announced by the EPA last year regulating methane emissions from new and modified oil and gas sources, and a rule issued earlier this year regulating methane emissions from oil and gas drilling on federal land.

Read the U.S.-Canada joint statement at

Pugh(eee)…Get Those Lands Outta Here: A Look at the Pugh Clause

For the unwary, Pugh clauses (pronounced “Pew”) can sometimes stink.  Although it is a fairly common provision in many fee oil and gas leases today, there is no industry standard Pugh clause.[1] As a result, the many variations of the Pugh clause can provide unpleasant surprises to both lessors and lessees who assume that all Pugh clauses operate similarly.  From an industry perspective, it is essential for landmen negotiating oil and gas leases to understand how a Pugh clause will operate an­­­­d potentially affect other provisions in the lease.  Additionally, with the sharp decrease in oil prices, many oil and gas companies have pushed drilling schedules into the indefinite future.  The delay in drilling necessitates a careful review of the underlying lease portfolios to determine when certain leases will expire. A thorough understanding of the effect of a  Pugh clause’s on a lease is vital to this review.

So What Is It?

As a general rule, production, or other operations, on “any part of the land, included in an oil and gas lease will perpetuate the lease beyond the primary term as to all of the land covered by the lease.”[2] Moreover, if lands are pooled or unitized, production or operations on any of the lands within the unit can extend all leases committed in whole, or in part, to the drilling or spacing unit.[3] This means that an oil and gas lease can be held past its primary term by production on only a small portion of the leased lands or on lands outside of the leased lands that are located in a drilling or spacing unit. Understandably, lessors can be less than thrilled to discover that all of their lands are locked-up by a lease when only a small portion of their lands are included within a drilling or spacing unit—preventing them from re-leasing their non-producing lands so that they can receive additional bonus payments, rentals, or production royalties from these lands. Without an “express provision in the lease, the lessor only has recourse to the implied covenant of reasonable development (or further exploration in a state that recognizes such a covenant)” to force additional development on the lessor’s lands or allow them to re-lease the lands altogether.[4]

A Pugh clause can prevent this scenario. Named after a Louisiana lawyer named Lawrence Pugh,[5]  the Pugh clause operates to sever the non-producing lands or interval based on some defined criteria, such as acreage or depth.[6] The impact of a Pugh clause “increases the burdens on the lessee who must take additional steps to maintain the lease as to the [non-producing portion]; this may include a return to delay rentals,” (if the lease is not a paid-up lease), “or initiation of drilling operations within a specified period.”[7] In other words, by including a Pugh clause in a lease, any production located on or attributed to leased lands will no longer be sufficient to extend the primary term for the entire leasehold. If the lessee takes no actions to extend the lease excluded by operation of the Pugh clause, the lease will expire as to these excluded lands. This provides an obvious benefit to lessors, who can once again make the forfeited lands available for lease. Since Pugh clauses are decidedly pro-lessor, they are “virtually always inserted into or attached to a lease at the insistence of the lessor’s attorney.”[8]

Horizontal and Vertical Pugh Clauses

It is important to note that Pugh clauses can be horizontal, vertical, or both.  A horizontal Pugh clause “has the effect of severing a leasehold as to the pooled and non-pooled portions on the basis of horizontal planes,” while a vertical Pugh clause “has the effect of severing a leasehold on the basis of vertical planes only.”[9] This means a Pugh clause can be structured by depth (e.g., severing all lands below 100 feet of a drilled well or the bottom of the producing zone), or by acreage.

Give Me An Example

Because there is no industry standard Pugh clause, there can be as many different forms of the clause as there are people drafting the clause.  The following is an example of a generic Pugh clause:

A producing well, or well capable of producing, will perpetuate this lease beyond its Primary Term ONLY as to those lands as are located within, or committed to, a producing or spacing unit established by Government authority having jurisdiction.[10]

This provision in an oil and gas lease operates to segregate the lease at the end of the primary term according to whether the leased lands were within a drilling or spacing unit established by the appropriate government agency. Any lands not located within a drilling or spacing unit would not be extended by production (keeping in mind, of course, that these lands could be extended by other provisions in the lease, such as those pertaining to drilling operations). As a title examiner, it’s not uncommon to see other triggering criteria in a Pugh Clause—such as one or two years after the end of the primary term, or when drilling operations on any portion of the leased lands cease for a specified amount of time.

It’s crucial to clearly specify how and when the clause will come into play, as illustrated by the following real-life Pugh clause:

Notwithstanding anything to the contrary herein, this lease shall terminate after the primary term as to all the lands not included within a drill site spaced unit as provided by the proper Governmental Authority….

This Pugh clause is poorly drafted because it segregates the leased lands only on the basis of whether they are within a “drill site spaced unit,” without clearly specifying that the spaced units must also be producing in order for the lease to be extended beyond its primary term for those lands.  Read literally, the provision raises the question of whether a lease would be extended for lands that are merely subject to a spacing order (and thus presumably within a drill site spaced unit) when there is no production within the drilling or spacing unit, assuming that there is production elsewhere on the lease lands, as was the case in this instance.[11] Although it’s likely that the parties to the lease intended that the clause include a production requirement, it’s uncertain how a court would rule if this clause was litigated, particularly since Pugh clauses tend to be strictly construed.[12]

Problematic Pugh clauses, such as the example above, often arise when the Pugh clause is merely copied and pasted from another oil and gas lease, which can result in omitted words or phrases, or inconsistencies with other provisions of the lease. Problems can also arise when a Pugh clause is drafted by a person who does not fully understand the impact of words or phrases included in, or excluded from, the provision.

Be Careful

As illustrated by the poorly drafted Pugh clause above, not all Pugh clauses are created equal, and it’s important to review and understand the specifics of a Pugh clause when negotiating an oil and gas lease, or when later evaluating how a Pugh clause affects the extension of a lease.


[1] 1 Bruce M. Kramer and Patrick H. Martin, The Law of Pooling and Unitization, § 9.01 (LexisNexis Matthew Bender 2015), hereinafter referred to as “Pooling and Unitization,” citing Robin Forte, “Helpful Hints: The ‘Pugh’ Clause,” 42 Landman 9 (May/June 1997) (“Just as there is no standard oil and gas lease, today there is no standard ‘Pugh’ clause.”).
[2] Adams, James W., Jr., “Lease Issues for Opinion Purposes,” Nuts and Bolts of Mineral Title Examination, Paper 11, Page No. 517 (Rocky Mt. Min. L. Fdn. 2015), hereinafter referred to as “Lease Issues”.
[3] Id.
[4] Pooling and Unitization § 9.01.  For a discussion on the implied covenant to develop as it relates to Montana law, see Miller, Adrian, “The Implied Covenant to Drill and Develop in Montana,” available at:
[5] Pooling and Unitization § 9.01, ft. 3.
[6] Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 669 (LexisNexis Matthew Bender 2015), hereinafter referred to as “Oil and Gas Law.”
[7] Pooling and Unitization § 9.01.
[8] Pooling and Unitization § 9.04.
[9] Oil and Gas Law § H Terms. According to one commentator, the terms “horizontal Pugh clause” and “vertical Pugh clause” are often mistaken with one another and, as a result, are used somewhat interchangeably within the industry.  Consequently, the commentator suggests that Pugh clause should clarify whether the provision affects depth or acreage. See
[10] This example is given in Lease Issues, p. 518.
[11] The question regarding this Pugh clause’s operation might be even more muddled in some states, such as New Mexico, which have standard spacing requirements.  See N.M. Admin. Code 19.15.15.
[12] Pooling and Unitization § 9.01. The treatise notes, however, that “strict construction is by no means uniform,” and “a few courts have seemed almost eager to interpret such provisions in favor of the lessor through readings that do not appear entirely reasonable.”  Id.

The Habendum Clause – ‘Til Production Ceases Do Us Part

The habendum clause is a fundamental provision of oil and gas leases. This clause (also called the term clause) sets forth the time period that the rights granted to the lessee under the lease are extended—i.e. how long the lease will be active.1


An habendum clause in an oil and gas lease typically contains two separate terms, the primary term and the secondary term. The primary term is a fixed period of time during which the lessee has the option, but not the obligation, to pay delay rentals and/or explore for and produce oil and gas. No actual production is necessary to keep the lease active during the primary term. Ten years used to be a common primary term; however, shorter primary terms (e.g. 1 to 5 years) are often seen in areas with proven fields or anticipated drilling.2 As with other lease terms, its length can be negotiated by the lessor and lessee; the relative bargaining power between the parties and the amount of bonus a lessee is willing to pay are important in determining term length.3

At the expiration of the primary term, the lease terminates as a matter of law unless production4 is achieved during the primary term. The time period under the secondary term is indefinite—so long as lease substances are produced, the lease remains in effect. While many leases expire at the end of the primary term without production, if production is achieved, it is not uncommon for oil and gas leases to be held by production for many years.

In having both a primary and secondary term, the interests of both lessors and lessees are represented. The fixed primary term protects lessors from having their mineral interests endlessly tied up without production and encourages development on the land. If production is not achieved by the lessee within the primary term, the lease terminates (unless otherwise extended, such as by other lease terms) and the lessor is free to re-lease his or her mineral interests. Conversely, if production is achieved, the lessee’s risk in expending substantial sums to develop the land is rewarded by extending the lease so long as production continues.5


Although there are numerous variations of habendum clauses, a typical habendum clause will read substantially as follows:

[T]his lease shall remain in force for a term of ___ years from this date, and as long thereafter as oil or gas or either of them is produced from said lands.6

Additionally, the phrase “produced in paying quantities” or “produced in commercial quantities” is commonly included in the clause, along with phrases allowing for production to come from lands pooled or unitized with the leased lands.7

Meaning of “Produced”

As noted above, the typical habendum clause requires that oil or gas be “produced” from the leased land to extend the lease beyond its primary term. In most states, “produced” means exactly that—oil or gas must actually be produced from the leased land. A minority of states, including Oklahoma and West Virginia, hold that discovery of oil or gas is sufficient—no production is actually necessary—to extend the lease beyond its primary term, although the well must be completed and capable of production, and the lessee must make diligent efforts to market.8 Another minority of states, including Montana and Wyoming, appear to differentiate between oil and gas, with the discovery of gas being sufficient to extend the lease beyond the primary term, while actual production for oil is necessary to extend.9 The distinction arises because oil can be produced and stored economically while gas generally cannot be stored economically above the ground.10

Some habendum clauses include language that the lease will be extended “so long as oil or gas is capable of being produced in paying quantities.” In such instances, actual production is not necessary to extend the lease beyond its primary term, but may require a well that can be turned “on” to produce in paying quantities without the addition of extra equipment or repair.11

Once the lease is extended into the secondary term, if production ceases the lease automatically terminates (unless otherwise extended by a different provision in the lease).12 However, courts have held that it is not required that production be entirely continuous throughout the extended term to hold the lease. Courts recognize that production may temporarily cease due to repairs, breakdowns, and reworking operations.13 Where the lease is silent, and cessation in production is litigated, the burden of proof rests on the lessee to show that the cessation was for a reasonable reason and for a reasonable amount of time. Courts vary in what constitutes a reasonable amount of time.14 For example, one court held that a four-year cessation in production was “temporary,” while another court held that a six-month cessation was “permanent.” To provide more certainty in the face of inconsistent court rulings, modern oil and gas leases often include a “cessation of production” clause that specifies when production must be continued after cessation for the lease to not terminate.15

Meaning of “Produced in Paying Quantities”

A question that frequently arises when construing an habendum clause is how much production is necessary—i.e. is any amount of production sufficient to hold the lease, or must the production reach a certain level? As noted above, modern oil and gas leases commonly include the qualification that production be in “paying” or “commercial” quantities. For leases that only state “production” is required, courts generally have construed the clause to include this qualification. Thus, regardless of whether the lease includes the qualification “in paying quantities,” the term “produced” typically means “produced in paying quantities.”16

The question then becomes what constitutes “produced in paying quantities.” The Kansas Court of Appeals stated the general rule:

[T]he phrase “in paying quantities” as used in an oil and gas lease habendum clause means production of quantities of oil or gas sufficient to yield a profit to the lessee over operating expenses, even though the drilling costs or equipping costs are never recovered, and even though the undertaking as a whole may thus result in a loss to the lessee.17

Put simply, a lease is considered “producing in paying quantities” if production revenue is greater than operating expenses.

In determining production revenue, any royalty paid to the lessor is excluded, although any payment to overriding royalty owners generally are included as revenue.18 For operating expenses, any direct costs to operate, such as labor costs, electricity for pumping units, taxes (but not income taxes) payable by the working interest owner(s), and day-to-day maintenance cost are included.19 There is some dispute among courts whether depreciation and overhead costs should be included as operating expenses.20 Initial expenditures, such as the costs of drilling, equipping, and completing are not included as operating expenses.21 Such analysis makes economic sense—after these initial expenditures, an operator will continue to operate so long as the production on a lease is marginally profitable in order to recover as much of these costs as possible.22

It is important to have a reasonable time period when evaluating production revenues against operating expenses. Leases may operate negatively in the short-term, but profitably in the long-term. One source notes that in almost every instance, a time period of at least a year was used by the courts to evaluate profitability, and frequently a time period of eighteen months to three years was used.23 In times of distressed market conditions, courts have used longer time periods or have assessed whether the lease would have been profitable under normal market conditions.24


An understanding of the habendum clause is crucial when negotiating a lease or when evaluating whether a lease has been held by production past its primary term. As you do so, keep in mind that other lease provisions not discussed in this article may also affect lease duration, such as shut-in royalty, pooling, unitization, Pugh, continuous operations, delay rental, and cessation of production clauses, among others. Additionally, be aware that the law varies from jurisdiction to jurisdiction, and may be different from the general principles discussed in this article.

1See PEC Minerals LP v. Chevron U.S.A., Inc., 439 F. App’x 413, 416 (5th Cir. 2011).
2John S. Lowe, Oil and Gas Law in a Nutshell (6th ed. 2014).
4Or a lease provision that serves as a substitution for actual production such as continuous drilling operations or payment of shut-in royalty.
5Lowe, supra note 2.
63 Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 603.3 (2014).
8See McVicker v. Horn, 322 P.2d 410 (Okla. 1958); Eastern Oil Co. v. Coulehan, 64 S.E. 836 ( W. Va. 1909).
9See Severson v. Barstow, 63 P.2d 1022 (Mont. 1936); Pryor Mt. Oil & Gas Co. v. Cross, 222 P. 570 (1924).
10See 2 Eugene Kuntz, A Treatise on the Law of Oil and Gas § 26.6 (rev. ed. 2014). See also Lowe, supra note 2.
11Martin & Kramer, supra note 6.
12See Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002).
13Martin & Kramer, supra note 6, at § 604.4.
15Id. See also Dave Hatch, Potential Pitfalls of Continuous Drilling Provisions in HBP Fee Leases (Apr. 10, 2014), available at:
161 Earl A. Brown, Earl A. Brown, Jr., & Lawrence T. Gillaspia, The Law of Oil and Gas Leases § 5.03 (2d ed. 2014).
17Avien Corp. v. First National Oil, Inc., 79 P.3d 223, 230 (Kan. Ct. App. 2003); see also Maralex Res., Inc. v. Gilbreath, 76 P.3d 626, 630 (N.M. 2003) (“To satisfy the habendum clause production must be in ‘paying quantities,’ such that the income generated from oil and gas production exceeds the operating costs.”).
18Lowe, supra note 2.
19Id. See also Martin & Kramer, supra note 6, at § 604.6(b).
20Martin & Kramer, supra note 6, at § 604.6(b).
21Kuntz, supra note 10, at § 26.7.
22Martin & Kramer, supra note 6, at § 604.6(b).
23Lowe, supra note 2.
24Id. See also Kuntz, supra note 10, at § 26.7.