TITLE UPDATE 2013, SELECTED ISSUES
IN OIL, GAS AND MINERAL TITLE
MICHAEL S. BROWNING
BURLESON LLP
112 E. PECAN STREET, SUITE 700
SAN ANTONIO, TEXAS 78205
Main:
210.870.2604
Fax:
210.870.2626
Cell:
210.274.1115
Website: www.burlesonllp.com
Michael S. Browning’s e-mail: [email protected]
HOUSTON BAR ASSOCIATION
Oil, Gas and Mineral Law Section
October 22, 2013
ROYALTY DEED INTERPRETATION
The interpretation of instruments conveying or
reserving royalty fractional interests remains an
area ripe with confusion, consternation, debate, and
litigation
for
landmen,
title
examiners,
and
mineral/royalty owners.
While royalty fractional interests can be created by
a plethora of liguistic variations, they can be
classified into just two (2) types of fractional
interests, a “royalty fraction” and a “fraction of
royalty”.
A distinction between a “royalty fraction” and a
“fraction of royalty” simply must be made.
When
dealing with the quantum of royalty to be conveyed
or reserved, the word “of” has the same mathematical
effect that fractions multiplied against each other
have. Simply put, the interest is reduced.
A “fraction of royalty” might be expressed as “1/2
of 1/8 royalty”, which equals a one-sixteenth (1/16)
royalty.
A “royalty fraction”, on the other hand,
might be expressed in terms such as “an undivided
one-thirty second (1/32) royalty.”
Why All the Confusion in the First Place
There has been a great deal of litigation on this subject,
much of which has arisen out of conveyances/reservations
drafted prior to the 1970s during a period when it was
generally assumed that the royalty provided for in an oil
and gas lease would never be anything different from oneeighth (1/8).
A right to a “1/4 of royalty” was essentially synonymous
with a right to one-fourth (1/4) of the one-eighth (1/8)
royalty
reserved
in
an
oil
and
gas
lease
for
conveyances/reservations drafted prior to the 1970s.
Each clause would be construed to cover a one-thirty
second (1/32) royalty.
For fifty or more years, a oneeighth (1/8) oil and gas lease royalty was the typical
royalty, and few people ever contemplated that the oneeighth (1/8) oil and gas lease royalty would ever change.
Fractional Royalty
The conveyance/reservation of a fractional royalty
is the conveyance/reservation of a fraction or
percentage of gross production as a free royalty.
The owner of such an interest is entitled to a
specific share of gross production, free of cost in
an amount determined by the fractional size of his
interest.
The share of production to which such an owner is
entitled
will
not
“float”
with
royalties
of
differing amounts reserved in oil and gas leases.
A fractional royalty interest can be created by a
conveyance/reservation in a variety of terms and
phrases, some examples of which are as follows:
1. “an undivided 1/16 royalty interest of any oil, gas, or
minerals that may hereafter be produced.” Masterson v. Gulf Oil
Co., 301 S.W.2d 486 (Tex. Civ. App.-Galveston 1957, writ ref’d n.r.e.).
2. “a fee royalty of 1/32 of the oil and gas.”
Caraway v. Owens,
254 S.W.2d 425 (Tex. Civ. App.-Texarkana 1953, writ ref’d).
3. “an undivided 1/24 of all the oil, gas, and other
minerals produced, saved, and made available for
market.” Miller v. Speed, S.W.2d 250 (Tex. Civ. App.-Eastland, 1952, no writ).
4. “a 1/4 royalty in all oil, gas, and other minerals in
and under, and hereinafter produced.” Arnold v. Ashbel Smith
Land Co., 307 S.W.2d 818 (Tex. Civ. App.-Houston 1957, writ ref’d n.r.e.).
5. “1/8 of the usual 1/8 royalty interest.”
131 S.W.2d 47 (Tex. Civ. App.-Beaumont 1939, error ref’d).
Allen v. Creighton,
Fraction of Royalty
Unlike a fractional royalty interest, the quantum of
production associated with a fraction of royalty
will “float”, depending upon the royalty reserved in
an oil and gas lease.
A conveyance/reservation of a fraction of royalty
creates a share in production in the amount of the
fraction multiplied by the royalty reserved in an
oil and gas lease.
A royalty interest which is a fraction of royalty
can be created by a variety of granting or
reservation clauses, including but not limited to
the following:
A. “1/16 of all oil and gas royalty”.
B. “an undivided one-half interest in and to all of
the royalty”. State Natl. Bank of Corpus Christi v. Morgan, 143 S.W.2d
757 (Tex. Com. App. 1940, opinion adopted).
C. “1/2 of 1/8 of the oil, gas and other mineral
royalty that may be produced”. Harriss v. Ritter, 279 S.W.2d
845 (1955).
To further illustrate this point, the following
examples assume that the underlying oil and gas
lease provides for a one-eighth (1/8) Lessor’s
royalty:
1. “An undivided 1/16 royalty interest” entitles the
owner to one (1) out of every sixteen (1/16)
barrels of production.
2. “An undivided 1/16 interest in and to royalty”
entitles the owner to one (1) out of every one
hundred and twenty-eight (128) barrels produced.
3. “An undivided 1/2 interest in and to royalty”
entitles the owner to one (1) out of every
sixteen (16) barrels of production. Williams & Meyers, Oil
and Gas Law, Section 327.2..
Can There Be a Hybrid of a Fraction of Royalty
and a Royalty Fraction?
One of the few instances where the share of production
attributable to a fractional royalty interest would “float” with
the royalty reserved in an oil and gas lease occurs where a
mineral interest owner first executes an oil and gas lease
providing for a royalty, such as one-eighth (1/8), and then
subsequently conveys a larger fractional interest such as a
perpetual undivided one-fourth (1/4) royalty in all oil and gas
and other minerals thereafter produced.
There, the grantee of the fractional royalty would only be
entitled to the proceeds from production up to the royalty
provided in the current oil and gas lease since the lease was
granted prior to the creation of his fractional royalty interest.
The fractional royalty interest owner in this example would
probably have a claim for breach of warranty against the grantor,
and once the underlying lease expired, the fractional royalty
interest owner would be entitled to the full 1/4 of gross
production.
Double Fractions
The granting or reserving of a fraction of royalty
becomes even more complex when double fractions are
utilized, i.e. “1/4 of 1/8 of all royalty…”.
Texas cases are generally uniform in holding that
such instruments are not ambiguous and convey
exactly the quantity of production described.
Indeed, most courts follow the “multiplication approach”
when interpreting instruments with double fractions, to wit:
A. Tiller v. Tiller, 685 S.W.2d 456 (Tex. App.-Austin 1985, no
writ) (holding that an instrument with the double fraction,
1/9 of 1/8, conveyed a 1/72 interest).
B. Helms v. Guthrie, 573 S.W.2d 855 (Tex. Civ. App.-Fort Worth
1978, writ ref'd n.r.e.) (holding that an instrument, which
recited an interest as “1/2 of a 1/8 royalty”, is the same as
1/16 of the total production).
C. Harriss v. Ritter, 279 S.W.2d 845 (1955) (holding that a
reservation of “1/2 of 1/8 of the oil, gas and other mineral
royalty” reserved a 1/16 “of the royalty,” rather than a 1/2
“of royalty”).
D. Allen v. Creighton, 131 S.W.2d 47 (Tex. Civ. App.-Beaumont
1939, error ref'd) (holding that a conveyance of “1/8 of the
usual 1/8 royalty” conveyed a right to 1/64 of production).
E. Richardson v. Hart, 185 S.W.2d 563 (1945), (holding the grant
of “1/16 of 1/8 of all of the oil royalty” created a fraction
of royalty equal to 1/128 “of the royalty”).
In nearly all the cases in which double fractions
are encountered, the second fraction is one-eighth
(1/8), leading one to believe that the use of double
fractions in conveyances which have been interpreted
by the courts leads to a result which was not
intended by the parties.
For instance, the oil and gas lease in Richardson v.
Hart provided for a one-eight (1/8) royalty
resulting in the grantees receiving an undivided
1/1024 interest in gross production.
This strict doctrine of construction was relied upon
and expanded further in Harriss v. Ritter, in which
an instrument reserving: (i) 1/2 of 1/8 of the oil,
gas, and other mineral royalty; and (ii) 1/2 of
bonus and rentals, was held to reserve a royalty of
1/16 of royalty, together with 1/2 of bonus and
rentals.
It is doubtful that in the Harriss case
that the parties intended to distinguish the various
lease benefits by reserving different fractional
interests in each.
Mineral/Royalty Distinction
Although this portion of the paper is titled and
dedicated to Royalty Deed Interpretation, it would
be remiss not to discuss some interpretive issues
surrounding whether an interest is “mineral” in
nature or “royalty” in nature
The rights and appurtenances comprising the mineral
estate are listed in, Altman v. Blake 712 S.W.2d 117
(Tex. 1986), holding that a mineral estate consists
of the following five (5) rights:
1. The right to develop (the right of ingress and
egress)
2. The right to lease (the executive right)
3. The right to receive bonus payments
4. The right to receive delay rentals
5. The right to receive royalty payments.
While each right is distinct in and of itself, the
nature of the mineral estate changes when the five
(5) Altman attributes are variously combined.
Interpretive
problems
have
arisen
in
the
construction of instruments that convey or reserve a
specified fraction of the oil, gas and minerals but
subsequently
include
limiting
language
or
reservations to strip the mineral interest of some
or all of the usual attributes of the mineral
estate; usually the right to execute oil and gas
leases (the executive right) as well as the right to
receive bonus payments and delay rentals.
This raises the question of whether a mineral
interest denuded of most or all of bundle of sticks
comprising the mineral estate, except the right to
receive royalty, remains mineral in nature so that
the owner’s royalty is calculated as a fraction of
royalty,
or
has
this
mineral
interest
been
transformed to a “royalty” interest so that the
owner’s royalty is calculated as a royalty fraction?
A
look
at
the
historical
treatment
of
this
phenomenon is helpful but by no means conclusive.
Some examples include the following:
1. In Watkins v. Slaughter, 189 S.W.2d 699 (1945),
the instrument in question reserved to the
grantor a 1/16 interest in and to all of the oil,
gas and other minerals in and under and that may
be produced from the land but provided that the
grantee would have the right to execute leases
and to receive all bonus and delay rentals.
However, the grantor would, “receive the royalty
retained herein only from actual production.”
[emphasis added]. The Watkins Court held the
retained interest was a 1/16 royalty fraction.
2. In Grissom v. Guetersloh, 391 S.W.2d 167 (Tex.
Civ. App. —Amarillo 1965, writ ref'd n.r.e.) the
instrument in question reserved to the grantor an
undivided 1/16 of all the oil, gas and minerals
in and under “…But the grantors waive all
interest
in
and
to
all
rentals
or
other
consideration which may be paid to grantees for
any oil and gas lease on the land or any part
thereof hereby conveyed.” The Grissom Court held
that the reserved interest was stripped of the
executive right, the right to bonus, and the
right to delay rentals.
However, the Court
declined to interpret the reserved interest as a
royalty fraction but held same to be a fraction
of royalty.
3. In Altman v. Blake, 712 S.W.2d 117 (Tex. 1986)
the Court construed a grant of, “An undivided
one-sixteenth (1/16) interest in and to all of
the oil, gas and other minerals in and under and
that may be produced…But does not participate in
any rentals or leases…” The Altman Court held
that a mineral interest shorn of the executive
right and the right to receive delay rentals
remains an interest in the mineral fee. Thus the
grantee would be entitled to a 1/16 fraction of
royalty.
4. In French v. Chevron U.S.A. Inc., 896 S.W.2d 795 (Tex. 1995)
the
granting
clause
created
a
mineral
interest
but
subsequent language indicated the mineral grantee would have
no executive rights, would receive no bonus, would receive
no delay rentals and that “this conveyance is a royalty
interest only.”
•
The French Court held that the mineral nature of the
granting clause was not transformed by the subsequent
stripping away of other mineral attributes except for
royalty.
•
Further, the French Court reasoned that if the parties had
intended a royalty conveyance, mentioning leasing, bonus,
and delay rentals would have been redundant.
•
Moreover, the identification of the conveyed interest as a
“royalty interest only” was not persuasive to the Court,
which mentioned that the Court of Appeals distinguished
Watkins v. Slaughter on the basis that the French Deed did
not provide for the grantee to receive the interest out of
“actual production.” French at 797. The result was that
the grantee received a fraction of royalty.
Temple-Inland Forest Products Corp. v. Henderson
Family Partnership, Ltd, 958 S.W.2d 183 (Tex. 1997) the
5. In
two (2) instruments at issue each granted an undivided
15/16 interest in the oil, gas and minerals in and
under and that may be produced from the tracts covered.
However, the instruments further provided that the
undivided one-sixteenth (1/16th) interest in the oil,
gas and other minerals retained and reserved by the
Grantor: shall always be a royalty interest; would not
bear any of the cost of exploration, development and
production; and that Grantor’s one-sixteenth (1/16)
royalty interest shall be delivered free of cost.
• Considering the language of the instrument in its
entirety, particularly the number of times the
instrument referred to the reserved interest as a
royalty as well as the fact that the retained
interest was free of cost, the Temple-Inland Court
held that the reserved royalty interest was a 1/16
royalty fraction.
As to what guidance the above line
provides, it can reasonably be said that:
of
cases
I. A conveyance/reservation of a mineral interest
stripped of all of its components other than the
right to receive royalty remains mineral in
nature resulting the grantor/grantee receiving a
fraction
of
royalty
instead
of
a
royalty
fraction; and;
II. stripping away all of the components of the
mineral
estate
in
a
conveyance/reservation
coupled
with
some
additional
distinguishing
factor (multiple reference to the word “royalty”,
reference to “actual production”, reference to
the interest being “free of cost”) can result in
the transformation of a conveyance/reservation
from being mineral in nature to that of a royalty
fraction.
However, as a practical matter, the cautious
examiner will not presume to know which kind of
interest an instrument creates unless the language
is unequivocal or nearly identical to one of the
instruments decided in the above cases.
Is It Possible To Have The Hybrid Characteristics of
a Fractional Royalty Coupled With Some Mineral Fee
Attributes?
Courts have shown a willingness to interpret an
instrument
as
having
hybrid
characteristics
containing a conveyance/reservation of a fractional
royalty interest along with some other attributes of
the mineral estate.
As such, it is possible to
attach such mineral rights to a fractional royalty
without transforming such fractional royalty into a
fraction of royalty.
In Elick v. Champlin Petroleum Co., 697 S.W.2d 1 (Tex.
App. —Houston [14th Dist.] 1985, writ ref’d n.r.e.) the
Court
addressed
an
instrument
with
the
following
reservation:
“SAVE AND EXCEPT an undivided 1/32 royalty interest in
and to all of the oil, gas and other minerals in, to
and under and that may be produced from the land
herein conveyed to be paid or delivered unto said J.J.
Elick, his heirs, or assigns, as his own property free
of cost…
It is further expressly agreed and understood that the
said
J.J.
Elick,
his
heirs
or
assigns
shall
participate in one-half of the bonus paid for any oil,
gas or other mineral lease covering said land and
shall participate in one-half of the money rentals
which may be paid to extend the time within which a
well may be begun under the terms of any lease
covering said land and said J.J. Elick, his heirs or
assigns shall join in the execution of any future oil,
gas or mineral lease.” [emphasis added].
The Elick Court concluded that the interest reserved
was simply a combination of diverse components of
the mineral estate, resulting in ownership of a onethirty second (1/32) royalty fraction, coupled with
a right to receive one-half (1/2) of all bonuses and
rentals, together with the power to join in
execution of leases in order to protect the
grantor’s interest in bonus and rents which might be
paid thereunder.
More recently, the Corpus Christi Court of Appeals
Wynne/Jackson
Development
v.
PAC
Capitol
in
Holdings, Ltd., No. 13-12-00449-CV, 2013 WL 2470898
(Tex. Civ. App.—Corpus Christi, 2013, pet. denied)
construed an instrument to have reserved a royalty
fraction, coupled with the right to receive one-half
(1/2) of the bonus and other payments, containing
the following reservation, to wit:
“There is excepted herefrom and reserved unto
Grantor a non-participating royalty of one-half
(1/2) of the usual one-eighth (1/8) royalty in and
to all oil, gas, and other materials produced, saved
and
sold
from
the
above-described
property,
provided, however, that although said reserved
royalty is non-participating and Grantee shall own
and possess all leasing rights in and to all oil,
gas and other minerals, Grantor shall, nevertheless,
have the right to receive one-half (1/2) of any
bonus,
overriding
royalty
interest,
or
other
payments, similar or dissimilar, payable under the
terms of any oil, gas and mineral lease covering the
above-described property.” [emphasis added].
While the interpretation of the instrument in the
Wynne/Jackson Development case appears consistent
with relevant case law, the analysis utilized by the
Court is troubling.
The Court appears to rely on
Harriss v. Ritter, 279 S.W.2d 845 (1955) when it
found:
“[T]he reservation is susceptible of but one
interpretation." Id. The court held, “as a matter of
law that the term ‘one-half of one-eighth of the
oil, gas and other mineral royalty’ could have but
one meaning and that is 1/16th of the royalty on all
the oil, gas and other minerals that may be produced
from said land.” Id. Again, this is consistent with
the interest being a fractional royalty. Here, the
only difference in the relevant language is that the
words “the usual” are used to qualify the one-eighth
royalty.” (Emphasis added) Wynne/Jackson Development
at page 3.
The Texas Supreme Court in Harriss v. Ritter held
that the reservation of one-half of one-eighth (1/2
of 1/8) of the oil, gas and other mineral royalty
yielded a one-sixteenth (1/16) fraction of royalty
as opposed to a fractional royalty.
As such, it
Wynne/Jackson
appears
that
the
Court
in
the
Development case may have either misconstrued the
holding in Harriss v. Ritter or was attempting to
distinguish the Wynne/Jackson Development case from
Harriss v. Ritter somehow.
In any event, the
analysis is unclear. Fortunately, the Wynne/Jackson
Development case is an unpublished Opinion but the
author felt it important to note the analytical
inconsistency.
VENDOR’S LIENS v. DEEDS OF TRUST
Hypothetical Scenarios
Hypothetical No. 1
By Warranty Deed with Vendor’s Lien dated January 15, 1927,
recorded in Volume 100, Page 111, Hazard County, Deed Records,
John Smith conveys to Joseph Doe, 100 acres, A-1, hereinafter
called “Blackacre”.
Thereafter, by Mineral Deed dated February 20, 1928, recorded in
Volume 125, Page 222, Hazard County, Deed Records, Joseph Doe
conveys to ABC Minerals and undivided one-half (1/2) interest in
the oil, gas and minerals in and under Blackacre.
Subsequently, the original note to John Smith as memorialized in
the Vendor’s Lien fell into default.
Thereafter, by Deed in Lieu of Foreclosure, dated March 25, 1929,
recorded in Volume 150, Page 333, Hazard County, Deed Records,
Joseph Doe conveyed to John Smith Blackacre.
Hypothetical No. 2
By Warranty Deed with Vendor’s Lien dated January 15, 1927,
recorded in Volume 100, Page 111, Hazard County, Deed Records,
John Smith conveys to Joseph Doe, 100 acres, A-1, hereinafter
called “Blackacre”.
Also on January 15, 1927, Joseph Doe executed a Deed of Trust
recorded in Volume 20, Page 50, Deed of Trust Records, Hazard
County, in favor of First National Bank, N.A. securing payment of
note with a final maturity date of July 10, 1991, and secured by
Blackacre.
Thereafter, by Mineral Deed dated February 20, 1928, recorded in
Volume 125, Page 222, Hazard County, Deed Records, Joseph Doe
conveys to ABC Minerals and undivided one-half (1/2) interest in
the oil, gas and minerals in and under Blackacre.
Subsequently, the original note to First National Bank, N.A. as
memorialized in the Deed of Trust fell into default.
Thereafter, by Deed in Lieu of Foreclosure, dated March 25, 1929,
recorded in Volume 150, Page 333, Hazard County, Deed Records,
Joseph Doe conveyed to First National Bank, N.A., Blackacre.
Issue
The issue raised by these two (2) hypothetical
scenarios is, “Does the conveyance of undivided onehalf (1/2) interest in the oil, gas and minerals in
and under Blackacre to ABC Minerals survive the Deed
in Lieu of Foreclosure in either hypothetical?”
Applicable Law.
There is distinction between a vendee and a
mortgagor.
A mortgagor, as the owner of the legal
estate,
can
convey
legal
title
of
mortgaged
property.
A foreclosure proceeding is required to
divest the rights of the owner of a legal interest.
Flag-Redfern Oil Co. v. Humble Exploration, Inc.,
744 S.W.2d 6, 8 (citing Bradford v. Knowles, 25 S.W.
1117 (Tex. 1894).
On the other hand, if a vendor's lien encumbers the
land, legal title does not pass to the vendee.
A
vendee owns the equitable interest along with a
contract for the purchase of land.
Therefore, if
the vendee sells all or part of the interest, the
conveyance is actually a transfer of an equitable
interest susceptible to rescission. Id. (citing
Texas Osage Co-Op Royalty Pool v. Benz, 93 S.W.2d
196, 198 (Tex. Civ. App. -Texarkana 1935, writ
dism'd.).
Considering the foregoing, under Hypothetical No. 1, Joseph Doe
owned only an equitable interest in and to Blackacre, and so when he
conveyed same to ABC Minerals, all that ABC Minerals acquired in
Blackacre was an equitable interest in and to an undivided one-half
(1/2) interest in the oil, gas and minerals in and under Blackacre. In this
scenario, default can lead to rescission of the contract.
• This [rescission of the contract] can be accomplished through
foreclosure, or privately when the vendee executes a deed
reconveying the property. Id. at 9.
• As such, under Hypothetical No. 1, the Deed in Lieu of Foreclosure
extinguished the rights of ABC Minerals in and to undivided one-half
(1/2) interest in the oil, gas and minerals in and under Blackacre.
Conversely, under Hypothetical No. 2, Joseph Doe, as
mortgagor, holds the legal estate to Blackacre,
while First National Bank, N.A. holds only equitable
title.
• ABC Minerals as an intervening purchaser of a
legal interest is granted legal title which is
superior to the mortgage although subject to the
mortgagee's rights. Id. at 9.
• The Deed of Trust did not vest First
Bank, N.A. with title to Blackacre.
National
• As such, under Hypothetical No. 2, the Deed in
Lieu of Foreclosure did not extinguish the rights
of ABC Minerals in and to undivided one-half (1/2)
interest in the oil, gas and minerals in and under
Blackacre.
Relevance to Title
The author has included this topic as for three (3)
reasons:
1. Because this point of law turns on a fine
distinction which could easily be missed by the
unwary;
2. Because a recent case with similar issues
recently handed down, See Glenn v. Lucas,
S.W.3d 268 (Tex. App. -Texarkana 2012); and
was
376
3. Perhaps most important, is that many of the
runsheets upon which title is based routinely
leave off old Releases of Vendor’s Liens, old
Deeds of Trust, and other similar instruments
which again, could cause this issue to be missed
by the unwary, or might lead to unneeded
requirements.
COMMUNITY LEASES
WHAT IS A COMMUNITY LEASE?
A Community Lease is created when separately owned
tracts of land are included by the executive rights
owners in a single oil and gas lease.
These separate tracts and all mineral and royalty
interests within them are treated as pooled, on a
surface acreage basis, for the duration of the lease
as a matter of law, in the absence of an express
provision to the contrary.
Parker v. Parker, 144 S.W.2d 303 (Tex.Civ.App. --Galveston
1940, writ ref’d); French v. George, 159 S.W.2d 566
(Tex.Civ.App. --Amarillo 1942, writ ref’d); Southland
Royalty Co. v. Humble Oil and Refining Co., 249 S.W.2d 914
(Tex. 1952).
NON-EXECUTIVE INTERESTS and COMMUNITY LEASES
A Little History.
Considering
the
far
reaching
ramifications
surrounding Texas law concerning pooling of nonexecutive interests it is a prerequisite to review
the historical basis for such law. In this respect,
it is probably safe to say that the nightmares
experienced by Texas executives rights owners,
Lessees and title examiners in connection with
Community Leases had their genesis in the Texas
Supreme Court’s 1943 decision in Brown v. Smith, 174
S.W.2d 43 (Tex. 1943).
The Blackacre executive whose tract was burdened
with a one-thirty-second (1/32) NPRI, and the
Whiteacre executive joined in the execution of an
Oil and Gas Lease covering both Blackacre and
Whiteacre contained a provision which expressly
pooled the royalty interests of these parties.
Black
Acre
White
Acre
Both tracts covered by a single OGML
Specifically, the Brown Court held that despite the
fact that the Blackacre executive had dedicated
Blackacre to a Community Lease, and further despite
the fact that such lease contained a provision
purporting to pool royalty interests in Blackacre
and
Whiteacre,
the
non-participating
royalty
interest produced and saved from Blackacre was not
pooled.
Basically, the Brown Court’s holding directed that
while
executives
in
Texas
are
allowed
to
unilaterally determine lease terms pertaining to
such important matters as:
1.
2.
3.
4.
5.
6.
bonus;
delay rental;
drilling obligations;
shut-in royalty;
length of the primary term; and
(arguably most important to the non-executive)
the quantum of royalty to be paid,
and that even though these matters may directly
impact the economics of the non-executive interest,
the executive is nonetheless precluded from pooling
the non-executive’s interest. Id.
By denying the executive the authority to pool the
interest of his non-executive, the Texas Supreme
Court in Brown set the stage for a series of
ratification
decisions
which
afford
the
nonexecutive the best of all possible worlds.
More specifically, the Texas courts since Brown have
given a non-executive whose interest has been made
subject to an Oil and Gas Lease which purports to
pool such interest an option; he/she can either
ratify the pooling provision and secure the benefits
thereof or not, depending on which alternative best
suits him/her.
In Montgomery v. Rittersbacher, 424 S.W.2d 210,
(Tex. 1968), the Texas Supreme Court held that
pooling or apportionment of royalties provided for
in a multi-tract lease, in which some tracts, but
not all, were burdened by a non-executive interest,
gives rise to an “implied offer” in favor of the
non-executive to apportion royalties if he so
desires.
The unauthorized pooling complained of in Montgomery
occurred under an Entireties Clause providing that
all royalty accruing under the subject multi-tract
Oil and Gas Lease was to be treated as an entirety,
to be divided among and paid to the separate owners
in the proportion that the acreage owned by each
bore to the entire leased acreage.
The Montgomery Court held that the (Montgomery
Lease)
entireties
clause
is
“virtually
indistinguishable” from a pooling clause in that
both
“change
the
aggregate
ownership
of
the
[nonexecutive] ... and, in effect, would allow the
owner of the executive rights to either diminish or
enlarge the ownership of [such nonexecutive].” This
being the case, the consent of the nonexecutive to
apportionment of royalties under an entireties
clause must be obtained just as it must where the
apportionment is effected under a pooling clause.
Where
the
Lessors/Executive
Rights
owners
are
authorized to commit, the tracts, and all mineral
and royalty interest within such tracts, the act (in
other words, upon the execution thereof) of granting
a community lease with respect to the separately
owned tracts, results by implication as a matter of
law in the pooling of the mineral and royalty
interests in those tracts.
The “implied offer to pool” under Montgomery places
the non-executive interest owner in the “driver’s
seat” when deciding to ratify the Community Lease or
not.
20 Acres
100 Acres
20 Acres
100 Acres
20 Acres
100 Acres
What if my Lease contains an “antientireties” clause or “anticommunitization” clause?
Many Texas Oil and
entireties”
clauses
clauses similar to:
Gas
or
Leases contain “anti“anti-communitization”
If this lease now or hereafter covers separate
tracts, no pooling or unitization of royalty
interests as between any such tracts is intended or
shall be implied or result merely from inclusion of
such separate tracts within this Lease, but lessee
shall nevertheless have the right to pool or unitize
as provided above, with consequent allocation of
production as provided above.
As used in this
paragraph, the words, “separate tract” mean any
tract with royalty ownership differing, now or
hereafter, either as to parties or amounts, from
that as to any other part of the leased premises.
In Verble v. Coffman, 680 S.W.2d 69 (Tex.Civ.App. -–
Austin 1984, no writ) and in London v. Merriman, 756
S.W.2d 736 (Tex.Civ.App. -–Corpus Christi 1988, writ
denied) both Courts allowed a non-executive whose
interest had been dedicated to a multi-tract Oil and
Gas Lease to share in benefits accruing to other
lease tracts irrespective of the fact that in both
cases:
1. There had been no actual pooling of the nonexecutive’s tract, either with other tracts covered
by the Oil and Gas Lease or with external acreage;
and
2.The executive rights owners and their Lessee had
inserted an “anti-entireties” clauses or “anticommunitization” clauses in the Oil and Gas Leases
expressly providing that there was to be no
apportionment
of
royalties
among
the
separate
tracts.
Texas
courts
have
suggested
that
anticommunitization
can
be
obtained
by
expressly
excluding the mineral estate of the “other” interest
owners from the lease or by executing separate
leases with regard to the tracts involved.
There is substantial doubt as to whether anticommunitization may be achieved by relying on
creative drafting measures in an Oil and Gas Lease
because it may very well be that the holder of the
executive right is precluded from excluding the nonexecutive’s interest from a pooled unit without the
non-executive’s consent, failing which the executive
may be exposed to liability. See Smith, “Implications
of a Fiduciary Standard of Conduct for the Holder of the
Executive Right”, 64 Tex.L.Rev. 371 (1985).
Who Would Bear Any “Excess” Royalty?
“Excess” royalty may be described in a scenario when
a non-executive in a non-drillsite tract ratifies
underlying Oil and Gas Lease, thus apportioning
(albeit constructively) royalties across intra-lease
tracts.
Although there is very little case law addressing
the issue of who is to bear any “excess” royalty the
authority which does exist indicates that an
“excess” royalty burden would fall on the executive.
See MCZ, Inc. v. Triolo, 708 S.W.2d 49 (Tex. Civ.
App. –Houston [1st Dist.] 1986, no writ).
The MCZ Court rejected that argument and held that
absent bad faith on the part of the lessee, it is
the Lessor/Executive who bears the “excess” royalty
burden when non-executive interest owner elects to
ratify the unauthorized pooling of his/her interest.
MCZ at 56.
The MCZ Court stressed the fact that the underlying
Oil and Gas Lease contained both a proportionate
reduction clause and a general warranty of title
with no express exception being made for the nonexecutive’s interest. MCZ at 54.
What the MCZ Court did not address
and what remains an open area of law
is a scenario in which an underlying
Oil and Gas Lease does not…
1. Contain a Warranty Clause and/or
2. Does not contain a Proportionate Reduction
Clause.
If an underlying Oil and Gas Lease does not contain
a Warranty Clause but does include a Proportionate
Reduction Clause, and in the event the non-executive
interest owner(s) burden exceeds the Executive’s
royalty share, the Lessee would likely have to
absorb the difference given that a Proportionate
Reduction Clause can only take the executive down to
zero, and the Executive has no warranty exposure for
the balance.
It is important to note that in MCZ, Inc. v. Triolo,
the underlying Oil and Gas Lease contained a
provision indicating that "[a]ll royalty covered by
this lease, (whether or not owner by lessor) shall
be paid out of the royalty herein provided."
ALLOCATION WELLS
What is an Allocation Well?
An Allocation Well is a Texas Railroad Commission
designation for a proposed horizontal well for which
the operator does not have a Production Sharing
Agreement or at least sixty-five percent (65%) of
the working interest owners and royalty interest
owners signed up for each included oil and gas lease
and unit.
Horizontal Wells
The Texas Railroad Commission defines a horizontal
drainhole well as “[a]ny well that is developed with
one
or
more
horizontal
drainholes
having
a
horizontal displacement of at least 100 feet.” 16
TEX. ADMIN CODE § 3.86(a)(4) (2000) (R.R. Comm’n of
Tex., Horizontal Drainhole Wells).
Horizontal drilling increases the exposure of the
perforated (i.e. producing) portion of the wellbore
by thousands of feet over a traditional vertical
well.
• As such, the efficient gains
extraction are exponential.
in
hydrocarbon
• In other words, as the amount of source rock
exposed to the wellbore increases, production
rates have skyrocketed from once hundreds of feet
of productive formation exposed, to the thousands
of feet of productive formation exposed today.
Further, as lateral lengths for each well continue
to increase, operators may now access more of a
particular
formation
through
fewer
surface
locations, including the ability to access areas
otherwise impossible to reach.
•
Indeed,
this
past
decade
has
seen
an
unprecedented boom in horizontal drilling in Texas
and throughout the United States.
As with almost any new technological advancement,
horizontal drilling presents its own unique set of
legal and regulatory issues. To be sure, horizontal
drilling
has
challenged
the
Texas
Railroad
Commission and the Texas Court system to apply and
adapt traditional legal and regulatory concepts,
which have been developed for over a century for
vertical wells, to horizontal wells.
The Evolution of the Texas Railroad Commission Rules
Leading to Allocation Wells.
• Initially allowed as
production, the Texas
issued
permits
based
Agreements.
•
a means of maximizing
Railroad Commission has
on
Production
Sharing
A Production Sharing Agreement (“PSA”) is an
agreement between royalty, working and other
mineral interest owners with interests in multiple
pooled units and/or unpooled leases in which the
parties
agree
to
a
method
for
allocating
production from horizontal wells traversing these
lands.
A timeline of the evolution of the Texas Railroad
Commission Rules leading to Allocation Wells is as
follows:
1. In 1998 the Texas Railroad Commission first
established a procedure for permitting vertical
PSA wells drilled on or near lease-lines. Drafting
Production Sharing Agreements, 39th Annual Ernest E. Smith Oil, Gas and
Mineral Law Institute, at 4, March 22, 2013, Robert D. Jowers and
Mickey R. Olmstead. [emphasis added].
2. In 2006 the Texas Railroad Commission established
a procedure for permitting horizontal PSA wells.
Id. [emphasis added].
3. In 2007 the Texas Railroad Commission Staff
denied a permit for a PSA well because it had
less than 100% of the royalty interest owners
signed up. Devon Energy Production Co., LP then
appealed that denial to the Commissioners, who
granted the well permit and indicated that the
Staff was authorized to permit similarly situated
wells. Id.
4.
In 2008 the Texas Railroad Commission Staff
denied a permit for a PSA well that had less than
ninety percent (90%) royalty interest signed up.
Devon appealed the denial to the Commissioners.
The Texas Railroad Commission approved any PSA
well permit where each tract has at least sixtyfive (65%) working interest and royalty interest
signed up. Id.
5.
In 2010, after the Texas Railroad Commission denied Devon’s
proposed field rule language in Oil & Gas Docket No. 06-0262000
and Devon’s Motion for Rehearing was denied, Devon filed a well
permit application for an Allocation Well, the Taylor-AbneyObanion Allocation Well.
On April 21, 2010, the Texas Railroad Commission’s Director of the
Hearing Section, Mr. Colin Lineberry, notified Devon that based on
the representations that Devon holds leases on each of the tracts
crossed by the proposed wellbore and that there are no unleased
interests within 330 feet of any point on the wellbore, the Texas
Railroad Commission would process the Drilling Permit.
See Oil &
Gas Docket No. 02-0278952 the Proposal for Decision and Recommended Final Order in
the Application of EOG Resources, Inc., Klotzman Lease (Allocation) Well No. 1H,
Eagleville (Eagle Ford -2) Field, DeWitt County, Texas.
Despite no representation by Devon Energy that it had the
agreement of at least sixty-five percent (65%) of the interest
owners, the Texas Railroad Commission approved Devon’s Drilling
Permit.
Since that time, the Texas Railroad Commission has issued more
than sixty (60) Allocation Well Permits, and has not required the
previous minimum amount (sixty-five percent (65%)) of interest
owners’ execution of Production Sharing Agreements.
Scenarios for Allocation Well Use and the Applicable
Case Law Pertaining to Production Allocation in
Allocation Wells.
There are several scenarios in which an operator
might need to utilize an Allocation Well or utilize
a production allocation method as one would use for
an Allocation Well, to wit:
A. An operator, who owns 100% of the working
interest in two (2) or more adjacent tracts,
desires to drill a horizontal well traversing and
producing from each tract but the underlying oil
and gas leases covering these tracts do not allow
for pooling.
B. An operator, who owns 100% of the working
interest in two (2) or more adjacent tracts,
desires to drill a horizontal well traversing
and producing from each tract but the pooling
provisions of one or more of the underlying
oil and gas leases covering these tracts has
been maximized.
Pooling
Maximized
C. An operator who owns 100% of the working
interest in two (2) or more adjacent tracts,
desires to drill a horizontal well traversing
and producing from each tract but one or more
of these tracts contains an unleased/unpooled
undivided mineral interest owner.
50%
Unleased
D. An operator who owns 100% of the working
interest in two (2) or more adjacent tracts,
desires to drill a horizontal well traversing
and producing from each tract but one or more
of these tracts contains an un-ratified nonexecutive interest owner.
½ of Royalty
N.P.R.I.
E. An operator who owns 100% of the working interest
in two (2) of three (3) tracts adjacent tracts,
desires to drill a horizontal well traversing and
producing from each tract but in the third tract
such operator owns only a 50% working interest
while the reaming 50% is owned by another
operator whose interest is not pooled.
50% W.I. = ABC Oil;
50% W.I. = XYZ Oil
Unfortunately, there is scant legal authority to
rely upon. The one case which supports the position
that operators are entitled to cross lease lines
without
pooling
the
interests
involved
(“allocating”) and provides some guidance as to an
operators obligations to allocate production is
Browning Oil Co. v. Luecke, 38 S.W.3d 625 (Tex. App.
—Austin 2000, pet. denied).
In Luecke, the operator drilled two (2) horizontal
wells that traversed tracts owned by the Lueckes, as
well as several other tracts, and then purported to
pool the Lueckes’ lands into Units that failed to
comply with the Lueckes’ oil and gas lease antidilution clauses.
The Lueckes contended that such
pooling
was
ineffective
as
to
them,
thereby
entitling them to royalties based upon all the
production from the first well and royalties based
on all the production from the second well. Id.
A few of the relevant holdings from Browning Oil Co. v.
Luecke are as follows:
I. Each tract traversed by the horizontal wellbore is a
drillsite tract, and each production point on the
wellbore is a drillsite. Browning Oil Co. v. Luecke at
634.
II. The measurable portion of a horizontal well lies
between the initial penetration point and the terminus
point. Id at 635.
III.
If
a
horizontal
drainhole
traverses
and
is
producing from a tract with an unpooled/unleased
interest owner, and such interest is not validly
pooled, such unpooled interest owner is entitled to a
share of production that can be attributed to their
tract
with
reasonable
probability.
Id
at
647.
[emphasis added].
Procedurally, the Austin Court of Appeals remanded
the Luecke case back to the trial court for a new
trial on damages consistent with the Austin Court of
Appeals’ Opinion.
Thereafter, the parties settled
the case.
As such, the Luecke Opinion failed to
address:
A. What is “reasonable probability”?
B. Who has burden of proof?
C. What is the measure of damages if
probability” cannot be ascertained?
“reasonable
Possible Allocation Calculation Methods.
With respect to the question of “What is the best
methodology to satisfy the ‘reasonable probability’
standard set forth in Browning Oil Co. v. Luecke?”,
the short answer is that no one really knows. There
are several calculation methods each with their own
positive and negative attributes, a few examples are
listed below, to wit:
1. Surface Acreage Basis:
simply calculating the
production attributable to a given tract based on
the quantum of acreage of such tract divided by
the total surface acreage of a “Production Unit”.
Positives:
(a) known calculation method (same
method utilized for most pooled units); (b) simple
calculations; and (c) maintains the same standard
of measurement (acreage) so that ownership totals
will equal 100%.
Negatives: (a) would require expert testimony to
a scientific level of exactness confirming that
the
entire
reservoir
under
such
tract
is
homogenous and isotropic, which is probably not
achievable; (b) most likely fails to comply with
the ruling in Browning Oil Co. v. Luecke; (c) most
likely method to be attacked as “forced pooling”.
(640 Acre Unit)
(80 Acres)
(80 Acres)
(120 Acres)
(160 Acres)
(40 Acres)
(80 Acres)
(80 Acres)
2.
Productive Horizontal Drainhole Length: by definition productive
horizontal drainhole length is the horizontal length of the
wellbore path that begins at the first take point and runs along
the surveyed wellbore path to the last take point. Calculations
utilizing this method would consist of the numerator being the
length (in feet) of the productive horizontal drainhole traversing
the tract in question with the denominator being the total length
(in feet) of productive horizontal drainhole. See Drafting Production
Sharing
Agreements,
39th Annual Ernest E. Smith Oil, Gas and Mineral
Institute, at 10, March 22, 2013, Robert D. Jowers and Mickey R. Olmstead.
Law
Positives:
(a) in the author’s experience, the most utilized
calculation method thereby moving closer to an “industry standard”;
(b) comes closest to complying with the ruling in Browning Oil Co.
v. Luecke; and (c) appears to be a fair and reasonable method of
allocation, assuming supported by geological evidence. Id.
Negatives:
(a)
whether
this
calculation
method
establishes
“reasonable probability” necessitates expert testimony that the
reservoir under such tract is “reasonably” homogenous and isotropic
along the wellbore so each foot of wellbore can be expected to
produce as much as any other foot of wellbore; and (b) utilizes
different standards of measurement (number of feet v. acreage) so
that ownership totals will not equal 100%.
(First Take Point)
450 Feet
(Last Take Point)
1350 Feet
1350 Feet
1000 Feet
3.
Number of Perforations Along the Productive Horizontal Drainhole
Length: this method of calculation is essentially the same as the
“Productive Horizontal Drainhole Length” method listed as No. 2
above but incorporates the number of perforations along the
portion of the wellbore under a given tract instead of using the
number of feet the wellbore traverses under such tract. Here the
numerator would be the number of perforations along the productive
horizontal drainhole traversing the tract in question with the
denominator being the total number of perforations along the total
length of the productive horizontal drainhole.
Positives: (a) likely a more accurate measure of the production
attributable to a given tract than the “Productive Horizontal
Drainhole Length” method; (b) also appears to be a fair and
reasonable method of allocation, assuming supported by geological
evidence (uniformity of the quality of perforations); and (c)
appears to also satisfy the ruling in Browning Oil Co. v. Luecke.
Negatives:
(a)
whether
this
calculation
method
establishes
“reasonable probability” necessitates expert testimony that the
perforations along the productive horizontal drainhole under a
given tract are “reasonably” uniform so that each perforation can
be expected to produce as much as any other perforation along the
total length of the productive horizontal drainhole; (b) utilizes
different standards of measurement (number of perforations v.
acreage) so that ownership totals will not equal 100%.
(First Take Point)
(Last Take Point)
Confusion of Goods
As previously mentioned, the Luecke Opinion failed
to address: (A) What is “reasonable probability?”;
(B) Who has burden of proof?; and (C) What is the
measure of damages if “reasonable probability”
cannot be ascertained?
Indeed, the Lueckes,
Browning Oil, and the Court did not raise the issue
of commingling. Further, the author is unaware of
any Texas appellate court case in which a Confusion
of Goods argument was made in the context of a
lessor challenging the allocation method of the
lessee.
The Doctrine of Confusion of Goods (commingling)
provides that where goods of a similar nature and
value owned by different parties are commingled so
that a proper division among the owners as to their
preexisting rights cannot be made the burden is on
the one commingling the goods to properly identify
the aliquot share of each owner; thus, if goods are
so confused as to render the mixture incapable of
proper division according to the pre-existing rights
of the parties, the loss must fall on the one who
occasioned the mixture. Humble Oil & Refining v. West, 508 S.W.2d
812, 818 (Tex. 1974). [emphasis added].
To meet this burden, the commingling party would
have to show by a preponderance of the evidence and
with reasonable certainty the amount of oil and gas
produced from each of the tract penetrated by the
horizontal wellbore. See Exxon Corp. v. West, 543 S.W.2d 667, 673
(Tex. Civ. App. —Houston [1st Dist.] 1976, writ ref’d n.r.e., cert. denied
434 U.S. 875); Humble Oil & Refining v. West, 508 S.W.2d 812, 819 (Tex.
[emphasis added]. Failure to meet this burden
would result in the owner in each of the separate
tracts will be entitled to receive their ownership
share in production from the total oil and gas
Mooers v. Richardson Petro. Co., 204
produced from the well.
1974).
S.W.2d 606, 608 (1947).
Since the burden of proof shifts to the operator
after proof by the tract owners of their ownership
in an unpooled tract together with proof that they
did not consent to the commingling of production in
the horizontal wellbore, an important question to
ask is whether the computation of the production
allocable to each tract is capable of being
established with reasonable certainty.
See George A.
Snell, III, Pooling Issues – From A to Horizontal, San Antonio Association
of Professional Landmen, at 24, (March 12, 2012). [emphasis added].
While the Luecke Opinion did not address the
Doctrine of Confusion of Goods, the Luecke Court did
reject the Lueckes’ claims to recovery based on the
doctrine utilized for vertical wells drilled on
invalidly formed units.
This doctrine entitles the lessors of the well site
royalties on the full production from the well,
rather than a share of production proportionate to
the amount of acreage their tract has contributed to
the Unit in which such tract is located.
The Luecke Court opined:
“…we recognize the immense benefits that have
accompanied the advent of horizontal drilling,
including the reduction of waste and the more
efficient
recovery
of
hydrocarbons.
Draconian
punitive damages for a lessee's failure to comply
with applicable pooling provisions could result in
the curtailment of horizontal drilling. We decline
to apply legal principles appropriate to vertical
wells that are so blatantly inappropriate to
horizontal wells and would discourage the use of
this promising technology. The better remedy is to
allow the offended lessors to recover royalties as
specified in the lease, compelling a determination
of what production can be attributed to their tracts
with reasonable probability.” Browning Oil Co. v. Luecke at
647. [emphasis added].
The
rejection
by
the
Luecke Court to apply
traditional doctrines to measure damages suggests,
but is by no means conclusive, that Texas Courts are
willing consider the public policy implications of a
given remedy.
Therefore, it is possible, but again, not certain,
that a Confusion of Goods argument would not be
successful.
Thank You!
Should
anyone
have
any
questions,
comments or concerns, please do not
hesitate
to
contact
me
at
[email protected].