Held (or Held Up?) by Production

Special Topics Valuation Issues

Oftentimes differences are a matter of perspective.  Put another way – one person’s loss can be another person’s gain.  One of the thematic differences between producers and mineral owners is their perspective on “Held By Production.”  It elicits very different reactions depending on what side of the term one is on, and has a leverageable impact on value.  In this post, we decided to spend some time exploring this concept and its impact on the energy industry.

What Is “Held By Production”?

Held By Production (“HBP”) is a mineral lease provision that extends the right to operate a lease as long as the property produces a minimum quantity of oil and gas. The definition of HBP varies contractually by every lease it governs which is often misunderstood.  We have had discussions with a number people, including peers (as well as knowledgeable industry participants) who did not have a clear grasp of HBP and its exact meaning.  Some people thought HBP was governed by state law, regulatory agencies, or even accounting rules.  However, the truth is that the facts and circumstances that shape a lease as it pertains to HBP are all negotiable.  Therefore, by extension, the outcome of lease negotiations can have a spectrum of results: from being deemed balanced, to favoring the lessor (i.e., the mineral owner) or the lessee (i.e., the producer).

When we attended the NAPE Expo this summer, presenters from Wood Mackenzie pointed out that a trend on recent analyst calls was for management teams of operators to highlight the percentage of their leases that were HBP  (they mentioned that the Permian Basin was about 95% HBP due to decades of prior drilling).  Operators want investors to note this and (hopefully) be more attracted to their stock.

Why might someone be more attracted to an operator’s stock that has a large percentage of leases HBP?  Investopedia puts it this way:

The “held by production” provision enables energy companies to avoid renegotiating leases upon expiry of the initial term. This results in considerable savings to them, particularly in geographical areas that have become “hot” due to prolific output from oil and gas wells. With property prices in such areas generally on an upward trend, leaseholders would demand significantly higher prices to renegotiate leases.

What Does “Held By Production” Mean to Mineral Owners (Lessors)?

Mineral owners should have an understanding of how their lease terms impact drilling activity (and by extension – royalty payments) on their properties (a thematic element of the summer NARO conference). Lessors are challenging operators’ decisions not to drill on their land, even if prospects appear to be good. As a result, mineral owners are more interested in how certain clauses and term structures function in their leases.  A session at the NARO conference centered on how mineral owners could legally terminate their lease in order to re-lease their property to a more “motivated” or even “competent” operator.

Therefore, it is important for mineral owners to understand two lynchpin concepts as they pertain to defining HBP: the Pugh Clause and the Implied Covenant to Develop.

Pugh Clause

The Pugh Clause is named after Lawrence Pugh, a Crowley, Louisiana attorney who developed the clause in 1947, apparently in response to the Hunter v. Shell Oil Co., 211 La. 893 (1947). In this case the Louisiana Supreme Court held that production from a unit, including a portion of a leased tract, will maintain the lease in force as to all lands covered by the lease even if they are not contiguous.

This clause is most often cited in today in pooling for horizontal wells. There have been situations (depending on the clause’s language) whereby one well might maintain a large area (thousands of acres) defined as HBP. This is to an operator’s advantage and a mineral holder’s chagrin.

However, this can be negotiated to the mineral holder’s favor – particularly in active markets and basins. For example, we had a client that had a large tract of land in the Eagle Ford shale and was being courted by a number of eager operators. Ultimately, they negotiated a lease with an operator who contractually obligated the company to drill three wells per year on the property for the duration of the lease. Not too long after the lease was negotiated, the price of oil dropped in half and the operator was much less enthusiastic about having to drill three wells per year.

There are a number of nuances and factors to Pugh clauses (and similar lease clauses) that we won’t explore here, but suffice to say, it is a critical factor to defining a property as HBP or not.

Implied Covenant to Develop

Another aspect of lease law is centered around the concept called “Implied Covenant to Develop.”  Sometimes a lessors’ alternative is to attempt to find remedy through the implied obligation that the lessee failed to develop and operate the property as a reasonably prudent operator.  Forcing an implied obligation generally occurs through a lawsuit and is difficult to prove.  However, implied covenants have been addressed by courts from all producing states as well as the Supreme Court of the United States.

There are several potential examples  One example is discussed on a Gas & Oil Law blog:

Consider an oil and gas lease taken on 200 acres. Let’s say that thirty years ago one well was drilled on the 200 acre lease, and that this well unit only included 40 acres.  Under the implied covenant to reasonably develop, a judge may very well cancel the lease to the remaining, unused 160 acres (200 acres – 40 acres = 160 acres).  How could a judge do that?  The basic question that needs to be answered is whether or not the oil and gas producer has behaved as a reasonable oil and gas producer would in similar circumstances.  If any reasonable producer would have drilled more than one well on the 200-acre lease, then a reviewing judge might void the lease to the remaining 160 acres.  However, if the existing well was not a very good well, then it might be that the producer did behave reasonably when they decided not to drill additional wells.


Depending on which side of the negotiation one is on, HBP can be a favorable (or unfavorable) contributor to value. As such, it’s crucial to have an analyst who possesses knowledge from all sides of industry negotiations.

Mercer Capital has over 20 years of experience valuing assets and companies in the oil and gas industry. We have valued companies and minority interests in companies servicing the E&P industry and assisted clients with various valuation and cash flow issues regarding royalty interests. Contact one of our oil and gas professionals today to discuss your needs in confidence.