LOUISIANA MINERAL LAW
LEGAL UPDATE
Presentation and Materials by
JASMINE B. BERTRAND
and
JEREMY B. SHEALY
Materials also by
RANDALL C. SONGY
and
KEVIN M. BLANCHARD
1200 Camellia Boulevard, Suite 300 (70508)
P.O. Box 3507
Lafayette, LA 70502
Telephone: (337) 237-2660
Facsimile: (337) 266-1232
E-Mail:
mailto:songyr@onebane.com
bertrandj@onebane.com
shealyj@onebane.com
www.onebane.com
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Louisiana Mineral Law Legal Update
PART 1: CASE LAW UPDATE
A.
MINERAL LEASE CASES
1. Notice Provided to Lessee’s Sister Subsidiary Company Might Constitute Notice to the
Lessee: Estess v. Placid Oil Co., CIV.A. 12-0052, 2012 WL 1222729 (W.D. La. Apr. 10, 2012)
In Estess, the Plaintiffs brought suit against Placid Oil Company (“Placid”) alleging that
Placid failed to develop a 1972 mineral lease as a reasonably prudent administrator, failed to
seek a revision of the true drainage area for the unit well, and failed to pay royalties due to the
Plaintiff. Placid brought a motion to dismiss claiming prematurity of the claims, as under the
Louisiana Mineral Code, all claims of the Plaintiff required written notice and reasonable time to
respond and the Plaintiffs had failed to give such notice. The Plaintiffs had sent notice to Oxy
USA, Inc. (“Oxy”) giving notice of their demands regarding drainage and failure to develop the
property. Oxy is a separate subsidiary of Occidental Petroleum Corporation (“Occidental”),
which was the “eventual parent company” of both Oxy and Placid. A series of letters between
Plaintiffs and managing counsel for Oxy (who was also counsel for Placid) followed. Thus the
issue for determination was whether notice was provided to Placid in compliance with the notice
provisions under the Louisiana Mineral Code in order for the Plaintiffs to bring their claims.
The Western District cited La. R.S. 31:136, which requires a mineral lessor to give his
lessee written notice in order to make a claim against the lessee for claims of drainage or failure
to develop and operate the property as a prudent operator, and La. R.S. 31:137, which requires a
mineral lessor to give his lessee written notice in order to make a claim against the lessee for
failure to make timely or proper payment of royalties. The Court noted that both statutes require
the lessor to not only give notice, but require the lessor to allow the lessee reasonable time to
cure the alleged breach, prior to making a judicial demand. The Court also noted that the 1972
Lease included a provision which stated that “in the event Lessor considers that operations are
not being conducted in compliance with this contract, Lessee shall be notified in writing of the
facts relied upon as constituting a breach hereof and Lessee shall have sixty (60) days after
receipt of such notice to comply with the obligations imposed by virtue of this instrument.”
After examining the statutes and the lease language, the Court applied the facts to
determine that Placid had been placed on notice of the Plaintiffs’ claims. In this instance, written
notice from the Plaintiff was directed at Oxy, not Placid, which was not the lessee of record.
However, the managing counsel for Oxy was the same person as the managing counsel for
Placid. When counsel replied to the notice that was addressed to Oxy, “he made it clear in his
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reply correspondence that he was responding on behalf of Oxy and Placid, if for no other reason
than the fact he wrote one letter on Oxy letterhead and one on Placid letterhead, while serving as
managing counsel for both.” The Plaintiffs had received correspondence from managing counsel
on both Oxy and Placid letterhead. In his initial correspondence, managing counsel had directed
Plaintiffs to direct all correspondence to him. Thus, the Court found in favor of the Plaintiffs,
finding that the written notification made to managing counsel of Placid satisfied both the
Louisiana Mineral Code’s notice requirements as well as the requirements made by the parties to
the lease.
2. Lessee Found to Have No Cause of Action under LUTPA against Lessors: Bogues v.
Louisiana Energy Consultants, Inc., 71 So. 3d 1128 (La. App. 2 Cir. 8/10/11)
In Bogues, a group of 22 lessors sued Louisiana Energy Consultants, Inc. (“LEC”), their
lessee through assignment, seeking termination of the leases and damages for failure to timely
pay royalties and operate the leasehold as a reasonable and prudent operator, and breach of the
implied covenant of reasonable development. LEC filed a reconventional demand based on
claims of unfair trade practices under the Louisiana Unfair Trade Practices Act (“LUTPA”) and
of tortious interference with business, claiming lessors had “engaged in a campaign to discredit
LEC” in its negotiations to farm out its interests to third parties so that they (the lessors) could
negotiate more favorable terms with those third parties for development of the deep rights to the
lands covered by the leases. LEC claimed this made the lessors “potential business competitors.”
The Court noted that in order to recover under LUTPA, a plaintiff must prove fraud,
misrepresentation, deception or other unethical conduct on the part of the defendant, but that LUTPA
does not prohibit sound business practices or the exercise of business judgment. In finding that the
facts of the case did not lead to a cause of action under LUTPA, the Court stated that although the
lessors “were unhappy with the leasing arrangement” and with LEC’s operations thereunder, there was
nothing unethical about the meetings the lessors had amongst themselves to discuss same. Similarly,
the Court found that LEC did not have a cause of action for tortious interference with LEC’s business,
as LEC could not put forth evidence of any conversation between a particular lessor and any particular
potential farmee with whom LEC was trying to conduct business, nor any evidence of malice on the
part of the lessors.
3. Attorney’s Fees Denied in Lease Rescission Case: Adams v. JPD Energy, Inc., 87 So. 3d 161
(La. App. 2 Cir. 2/29/12)
This was the second disposition in Adams v. JPD Energy, Inc., a lease rescission case brought
before the Second Circuit. In the first disposition of the case, the Court held a 2008 mineral lease in the
Haynesville Shale to be null and void for failure of the parties to have a meeting of the minds or mutual
consent regarding the royalty percentage. The second disposition concerned whether the Adamses were
entitled to recover attorney’s fees under La. R.S. 31:206 and 31:207, which allow for an award of
attorney fees when a lease is extinguished or expired. JPD contended that the statutes only applied
where a valid mineral lease was extinguished and that here, no valid lease was ever formed.
The Second Circuit agreed with JPD. The Court stated that La. R.S. 31:206 et seq., refer to
authorization to cancel extinguished mineral rights from the public record. However, rather than being
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extinguished or expired, a lease found null is deemed never to have existed. Therefore the Court found
that La. R.S. 31:206 and 31:207 did not apply and an award of attorney’s fees was inappropriate.
4. Reformation of Lease Denied: Hall Ponderosa, LLC v. Petrohawk Properties, LP, 90 So. 3d 512
(La. App. 3 Cir. 4/4/12)
Hall Ponderosa executed a mineral lease with Petrohawk Properties covering its tract in Section
14 (Stella Plantation) in Red River Parish. Later, Hall brought this suit to have the lease reformed to
include its lands located in Section 13 in Red River Parish, which was left out of the original
agreement, allegedly, by mutual error, and seeking additional bonuses of $15,000.00 an acre based on
the additional acreage. The lessor’s basic argument was that while the left-out section of property was
never specifically mentioned during lease negotiations, each party intended to lease all of lessor’s
property. After trial on the merits, the trial court found in favor of the lessor, ordering the lease to be
amended to include the additional 144 acre tract and ordering the lessee to pay nearly two million
dollars as remuneration. In reversing the trial court, the Third Circuit found the record to be devoid of
any evidence of mutual error. The lessor never once mentioned owning the Section 13 property to the
lease broker during negotiations. The Court noted that the lessors did not attempt to have the extra
section included in the lease until nearly a year after the lease was signed. Finally, one of the lessor’s
principals testified that he signed the lease without reading it, while another said that he signed the lease
after seeing that it did not include a property description for the extra section. The Court held that this
negligence on their part precluded them from seeking reformation.
5. Permit to Drill Well Not a Title Defect for Purposes of Top Lease Agreement: Pilkinton v.
Ashley Ann Energy, L.L.C., 77 So. 3d 465, 2011 WL 5170296 (La. App. 2nd Cir. 2011)
Pilkinton involved an addendum to a top lease, in which the parties agreed that the top lease
was “expressly made subject” to the prior lease, that the top lease was not intended in any way to cloud
or impair the rights of the parties to the prior lease, and that the top lease would come into being “only
following the termination” of the prior lease, at which time the remaining bonus be paid. Another
provision waived warranty, emphasizing that the lessor would not be obligated to return any bonus
consideration on account of a failure of title. Upon execution, top-lessee gave to the lessors a draft for
$431,000—representing one-quarter of the $20,000 per acre bonus payment—which included a
provision reading “upon approval of title but not later than 20 banking days after sight.” Two weeks
later—and within the 20-day provision—the original lessee secured a drilling permit for a unit well.
The top-lessee viewed this as a title defect and refused to honor the draft.
The top-lessee argued that the 20-day provision on the draft, read together with the addendum
to the top lease agreement, set up a 20-day period within which the top lease agreement could fail to
become effective because of a “title defect.” The Second Circuit held that the language of the top lease
was clear and unambiguous, saying that a top lease, at its inception, exists as a “mere hope or
expectancy in the extinction of existing superior leasehold rights.” Importantly, the Court noted the
meaningful difference between the effects of permitting a well and those of drilling a well, on the
maintenance of a lease beyond its primary term under the standard habendum clause. Here, the
defendants had tried to avoid honoring the top lease agreement because the original lessee had secured
a drilling permit. But the act of securing a drilling permit would not by itself maintain the
lease. Because the well permit could not have a bearing on whether the original lease was extended, it
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could not be considered a flaw in the lessor’s title. The Court noted that some other type of title flaw—
like another party’s ownership of the mineral servitude burden on the land—might have triggered the
20-day provision in the top-lessee’s favor.
6. Double Damages and Attorney’s Fees Awarded where Concursus Filed After Royalty
Demand Made : Oracle 1031 Exchange, LLC v. Bourque, 85 So. 3d 736 (La. App. 3 Cir. 2/8/12)
In Oracle, royalty owners sent demand letters to three entities, Oracle, Delphi, and Exchange,
demanding payment of unpaid royalties. Thereafter, Exchange filed a petition for concursus and
Oracle deposited money into the registry. The plaintiffs then reconvened against Exchange and made
third party demands against Delphi and Oracle, asking for penalties and attorney’s fees under La. R.S.
31:139. The trial court awarded the royalty owners double damages and attorney’s fees. The
appellate court upheld the trial court’s decision. This damage award included Oracle and Delphi on the
theory that they all constituted a single-business enterprise. Although Exchange was the only company
with working interest in the assigned leases, the Court found that Oracle and Delphi had engaged in
other activities, including operating the well, depositing the money in the registry of the court in the
concursus proceeding, paying taxes on the oil sales, and writing the check for the only royalty payment
actually made. Additionally, all three entities were headed by the same person. The Court found that
penalties were appropriate, despite the defendants’ argument that their invoking a concursus proceeding
should preclude same. The Court stated that the defendants’ failure to pay was “willful or without
reasonable grounds,” finding little merit to the defendants’ arguments that they were unsure whether
royalties were due considering the “minimal amount” of oil produced and that there were unresolved
title problems with the lands covered by the leases. This was especially true where the defendants
chose to file the concursus proceeding only after “being prompted to take action by the royalty owners’
letter demanding payment.”
7. Fraud Claim Upheld in Favor of Lessor: Petrohawk Properties, LP v. Chesapeake
Louisiana, LP, 689 F.3d 380 (U.S. 5th Cir. 7/24/2012)
Petrohawk v. Chesapeake concerns competing leases negotiated during the rush to lease
the Haynesville Shale formation. In April 2008, the Stockmans executed an extension of their
existing lease with Chesapeake, which was to expire on July 14, 2008, receiving a $240,000
bonus. On May 8, 2008, the Stockmans were approached by a landman on behalf of Petrohawk
about leasing their property. The landman told the Stockmans that the extension was invalid
because it had not been recorded. The landman did not inform the Stockmans that the extension
was valid between the parties, despite it not having been recorded, and did not inform them that
they could be liable to Chesapeake by signing a competing lease. On May 9, 2008, the
Stockmans executed a lease with Petrohawk for a $1.45 million bonus. The landman described
the lease as a “placeholder” in order for Petrohawk to win the race to the courthouse. The
Petrohawk lease was recorded that same day, and the Chesapeake extension was recorded May
19, 2008. Before depositing the Petrohawk draft, the Stockmans confirmed that the extension
had not been recorded. He thereafter had an attorney draft a letter revoking his consent to the
Chesapeake extension and returned the bonus money. Petrohawk’s draft was due to be paid to
the Stockmans on July 2, 2008, prior to the expiration date of the Chesapeake lease, and
therefore Petrohawk dishonored the draft.
The Stockmans spoke with a Petrohawk
representative and was led to believe that either party could walk away from the May 9 lease, but
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that if the Stockmans did so, they would not receive the $1.45 million bonus. The Stockmans
were told that if they allowed a delay in payment until July 15, Petrohawk would increase the
bonus. On July 15, 2008, Petrohawk executed a second lease with the Stockmans, paying them a
$1.7 million bonus.
After a settlement between Chesapeake and the Stockmans, the Stockmans sued
Petrohawk for fraud in obtaining the first lease, Chesapeake sued Petrohawk for intentional
interference with its contract, and Petrohawk sought a judgment that its lease was valid or, in the
alternative, for a return of the bonus. The trial court found that Petrohawk procured the first
lease by fraud and rescinded the lease and dismissed both Chesapeake and Petrohawk’s claims.
In affirming the trial court’s decision, the Court first addressed the Stockmans’ fraud claim.
First, the Court found that the landman’s misrepresentation to the Stockmans regarding the
invalidity of the lease extension because of Chesapeake’s failure to record same was made as a
statement of fact so that the Stockmans would sign the Petrohawk lease and could form the basis
of a fraud claim.
The Court dismissed Petrohawk’s argument that the landman’s
misrepresentation of law could not give rise to a fraud claim. Second, the Court found evidence
of Petrohawk’s intent to defraud the Stockmans. Petrohawk’s landman had testified that she was
an experienced landman and a former paralegal very knowledgeable about Louisiana law. The
Court saw this as evidence that the landman knew she was lying to the Stockmans about the
validity of the Chesapeake extension. It found documentary evidence that Petrohawk “was
willing to say or do anything to” obtain the Stockman lease. The Court also found intent to
defraud through the landman’s statements to Mr. Stockman, when he voiced some legal concerns
related to the Chesapeake extension, that he should not worry, because “Petrohawk ha[d] an
office full of lawyers.” Third, the Court found that the district court’s determination that the
Stockmans relied upon the landman’s misrepresentations was not clearly erroneous. Finally, the
Court rejected Petrohawk’s argument that the Stockmans could have easily ascertained the truth,
stating that in order to do so, the Stockmans would have needed to consult with a knowledgeable
attorney because ascertaining the truth required special skills not possessed by a mere landowner.
The Court also found that the Stockman’s subsequent revocation of the first lease and acceptance
of the bonus did not amount to a confirmation of the fraud because it was done without actual
knowledge of the fraud. Petrohawk was not entitled to a return of the bonus because the second
lease was neither an amendment to the first, nor was it a novation. Chesapeake could not bring
its claim against Petrohawk because Petrohawk owed no individualized duty to Chesapeake.
8. Preliminary Acts Performed in Good Faith Constitute Commencement of Drilling
Operations: Cason v. Chesapeake Operating, Inc., 92 So. 3d 436 (La. App. 2 Cir. 4/11/12).
The Cason case concerns whether putting surveyors on the ground, staking the well,
cutting of trees and stacking of lumber constituted the commencement of operations for drilling
in compliance with the terms of a mineral lease with a primary term ending May 31, 2010, where
a drilling permit was not obtained until after the end of the primary term. The Court noted that
despite the lessor’s insistence that the preparatory work was “sluggish,” the evidence showed
that Chesapeake spent $8.5 million bringing in the eventually productive well. It discussed the
jurisprudence holding that the general rule is that actual drilling is unnecessary but that
preliminary acts performed in good faith may constitute commencement of operations. While
the preparatory work may have taken longer than normal, the terrain in the area made work
difficult. The Court also found that the lessor was properly enjoined from continuing to refuse
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right-of-way for a pipeline to be constructed from a section of land not covered by the lease
because of the lease’s adjacent lands clause.
B.
MINERAL RIGHTS CASES
1. Unilateral Execution of Royalty Amendment Found Effective: Cecil Blount Farms, LLC v.
MAP00—NET, 2012 WL 3025134, ___ So. 3d ___ (La. App. 2 Cir. 7/25/12):
On November 1, 2001, the parties executed and recorded a standard printed form royalty deed
with an insertion that the royalty was for a term of seven years. One month later, on December 3, 2001,
the mineral owner executed and recorded an amendment to the royalty deed to define the seven year
term more specifically. The amendment stated that the royalty was to be subject to “an initial period of
liberative prescription of seven (7) years from the date hereof. Thereafter, in the event of a cessation of
production the period of liberative prescription shall be one (1) year from the date of last production.”
The mineral royalty was subject to mesne conveyances as well as a recognition and confirmation of the
amendment to the royalty from the original mineral royalty owner. The recognition and confirmation,
however, was executed and recorded after the original mineral royalty owner had already conveyed his
interest in the royalty. In May 2009, the then-landowner/mineral owner advised the then-royalty
owners that the royalty had expired and demanded the execution of a release, claiming that the 2001
amendment was invalid because of failure of consideration, the grantee did not join in the amendment,
and it was not executed as an authentic act.
The Court first addressed the effect of the amendment. The royalty owners argued that the
original royalty deed provided for a fixed seven year term and that the amendment created a
prescriptive period of seven years. The landowner/mineral owner agreed with the royalty owners’
assessment, but argued that the amendment was ineffective for the reasons stated above. The Court
cited Louisiana Civil Code article 1839, requiring that immovable property be transferred by authentic
act or by act under private signature, and article 1837, which requires the signatures of both parties for
an act under private signature. However, the Court noted, the comments to article 1837 state that an act
under private signature can still be valid even when signed by only one party, when the party who did
sign asserts the validity against a non-signing party whose conduct reveals that he has availed himself
of the contract. The Court pointed out that in this case, the amendment benefited the royalty owner,
i.e., the party who did not sign the amendment. Although the original royalty owner had already
conveyed his interest in the royalty when he executed the recognition and confirmation, the Court
found that here, the original royalty owner evidenced acceptance by conveying the royalty interest one
day after they had become subject to the amendment. It further noted that the royalty purchaser
acquired the mineral royalty subject to the amendment, which had been recorded the previous day.
2. Contra Non Valentem Applied to Unleased Mineral Owner’s Claim: Wells v. Zadeck, 89
So. 3d 145 (La. 5/30/12)
The Wells case concerns a mineral servitude created in 1949 in favor of Mr. and Mrs. Wells,
burdening a one-half interest in and to 120 acres in DeSoto Parish. The owners of the other one-half
interest were Mr. and Mrs. Holmes. The Wellses divorced in the 1950s, with each of them receiving an
undivided one-fourth interest in and to the minerals in their community property settlement. In 1954,
Mrs. Wells executed a mineral lease. The Lease was released in 1958 when the well resulted in a dry
hole. In 1961, Mr. and Mrs. Holmes executed a mineral lease, the property was included in a unit, and
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production from that unit continued through 2007. However, Mrs. Wells, who had moved away from
the area after the release, never knew about the production. She died in 2002 never having received
any payment due her as an unleased owner. Her son, as successor, brought suit in 2009, only after
finding out about the production and lease after receiving a call from a landman interested in leasing his
mineral interest.
Zadeck, one of the defendants in the suit, filed an exception of prescription based on the theory
that Wells’ claim was quasi contractual, governed by a ten year prescriptive period. Zadeck stated that
it had ceased being the operator of the well in 1994 and that therefore the claim Wells had against
Zadeck for failure to pay him as an unleased owner had prescribed. The issue in the case was whether
the doctrine of contra non valentem, a doctrine that suspends the running of prescription, excused the
plaintiffs from having not timely brought an action against Zadeck for failure to follow its statutory
duty to make payments to the unleased mineral owner.
The Louisiana Supreme Court first set forth the four instances where contra non valentem can be
applied, finding the fourth, being “where the cause of action is not known or reasonably knowable by
the plaintiff, even though this ignorance is not induced by the defendant”, to be at issue. After a
discussion of the jurisprudence regarding application of the fourth category of the doctrine, the
Louisiana Supreme Court stated that the test for a determination of whether the doctrine should apply in
this case was whether Mrs. Wells’ inaction was reasonable in light of her education, intelligence, and
the nature of the defendant’s conduct. The Court took note that Mrs. Wells was an unsophisticated
single-mother who lived away from the area and who had never received her statutorily required
payment or notice of unitization. The Court stated that Zadeck would clearly have had notice that,
when it acquired only a one-half interest in the property through the Holmes’ lease, the other one-half
interest was owned by another person or entity. Zadeck failure to comply with its statutory duty to pay
its unleased interest owner was a factor the Court considered in assessing the reasonableness of Mrs.
Wells’ conduct, in light of her intelligence and situation. The Court stated that “an unleased mineral
interest owner, who was minimally educated and not living in the same parish where the subject unit
well was located, should not be required to continuously search the public records, make cold calls, or
investigate the possibility of a unit well not located on the property subject to the mineral servitude.” It
then held that Mrs. Wells’ particular inaction was reasonable and her ignorance of the claim was not
negligent, and that contra non valentem operated to suspend the running of prescription against the
claim.
3. Subdivided Tract Created Mineral Servitude Which Prescribed: Horton v. Browne, 2012 WL
2478274, ___ So. 3d ___ (La. App. 2 Cir. 6/29/12).
The Horton case concerns a donation inter vivos executed in 1997, wherein the mother of the
plaintiffs divided a 40 acre tract of land into three tracts, giving two 18.75-acre tracts to two of her
children and one 2.5-acre tract to one of her children. The donation further provided that each sibling
receive an undivided one-third interest in the minerals underlying the 40 acres, thus creating a single
mineral servitude burdening the tract. Through a series of transactions in 2002 and 2003, the acreage
was sold to Browne, the defendant, with the plaintiffs reserving mineral rights. No wells were spud on
the property until 2010. In the suit, the plaintiffs sought a declaratory judgment recognizing them as
owners of the minerals. The defendant sought declaration that the plaintiffs’ servitude had prescribed
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in 2007. The trial court determined that the donation inter vivos had created a servitude that prescribed
in 2007 for non-use, and that therefore the defendant was the owner of the mineral rights.
In the appeal, the plaintiffs made two basic arguments. First, the plaintiffs argued that the
1997 donation did not create a valid mineral servitude. They based this argument on La. R.S.
31:66, which provides that owners of several contiguous tracts can create a single mineral
servitude, stating that in this case, there was only one owner, in the singular. The Court
disagreed, however, finding that the donation of the surface rights and the donation of the
mineral rights were two separate donations, albeit encapsulated in the same instrument. The
plaintiffs’ second argument was based upon application of the doctrine of confusion. The
plaintiffs argued that the transfer resulted in confusion of ownership of surface and mineral
rights. However, in this instance, the dominant and the servient estates were never acquired in their
entireties by the same individual and therefore confusion did not apply.
C. OPERATIONS CASES
1. No Cause of Action against DNR where P&A of Wrong Well Saved Working Interest Owner
Money: Winn v. State Dept. of Natural Resources, Office of Conservation, 2012 WL 3192767, ___
So. 3d ___ (La. App. 2 Cir. 8/8/12):
In 2004, an employee of the Department of Natural Resources (“DNR”) directed an
independent contractor, pursuant to the department’s Abandoned Well Program, to plug what turned
out to be the wrong well. Winn, the working interest owner of the well, however, who owned two
wells in the area—the other of which was supposed to have been plugged—did not notice the error
until years later. Winn filed suit against DNR, the independent contractor, and the parties he had hired
to oversee physical operations of the well, seeking damages for lost production and the cost of drilling a
replacement well.
In affirming the trial court’s grant of summary judgment in favor of DNR and the independent
contractor, the Second Circuit agreed with the trial court that the well owner had failed to establish the
necessary element of damages to support a negligence claim against DNR. DNR had an expert
demonstrate that, because the well had been declining in production before its wrongful plugging, the
plaintiff had likely saved money because of the mistake. In other words, the plaintiff would have made
less money in production proceeds over the years than he would have been required to spend if he
would have had to shoulder the cost of plugging the well himself. The well owner, who admitted he
was not sophisticated in the oil and gas business, and had a hard time even finding his own well sites,
could not produce any contradictory evidence.
2. Transportation Costs Properly Deducted as Post-Production Processing Costs: Culpepper v.
EOG Resources, 92 So. 2d 1141 (La. App. 2 Cir. 5/16/12)
The sole issue in Culpepper was whether or not transportation costs could be properly deducted
from gross revenues when computing a lessor’s royalty payment when the contract language at issue
provided that royalties were determined upon gas production “computed at the mouth of the well.” An
earlier case, Merritt v. Southwestern Electric Power Co., 499 So. 2d 210 (La. App. 2 Cir. 1986) had
found the language “at the mouth of the well” to mean that compression costs were deductible post-
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production costs. The court found that, under the reasoning in Merritt, there was no market for the gas
“at the mouth of the well” because it was useless and had no market value until it was
transported. Because the parties had not provided otherwise by contract, the lessee properly withheld
transportation costs as post-production processing costs.
3. Pipeline Company with Expropriation Authority Has Much Discretion in Selecting Site:
Acadian Gas Pipeline Sys. V. Nunley, 46,648 La. App. 2 Cir. 11/2/11, 77 So. 3d 457, 458 writ
denied, 2011-2680 La. 2/10/12, 80 So. 3d 487
This case concerns a natural gas pipeline Acadian was constructing from Napoleonville
to Mansfield, a portion of which it sought to cross the Nunley’s 400-acre tract in DeSoto Parish.
After unsuccessful negotiations with the Nunleys, Acadian filed suit, alleging that it had acquired
expropriation authority through a certificate of transportation from the Department of Natural
Resources to acquire property necessary for transporting and supplying the public with natural
gas under Louisiana law. The trial court found in Acadian’s favor. The main issue on appeal
concerned the evidence at trial presented by Acadian and testimony by Acadian’s senior project
manager with respect to the route chosen for the pipeline. The Nunley’s took issue with the fact
that Acadian produced no data such as designs, photographs, field notes and constructability
notes with respect to the site selection process, but instead relied on the testimonial evidence of
the project manager. In its discussion, the Second Circuit noted that with respect to site
selection, the expropriator must act in good faith and consider factors such as costs,
environmental impact, long-range area planning and safety considerations. However, the Court
found that testimony alone may suffice to prove that the expropriator considered these factors.
PART 2: STATUTORY UPDATE
CHANGES TO “RISK FEE” STATUTE BY ACT 743 OF 2012
Act 743 of 2012 revises La. R.S. 30:5.1 to add new provisions for the creation of units for
“ultra deep structures” and also revises La. R.S. 30:10 to significantly change the operation and
dynamics of the “risk fee” provisions of the statute. This outline addresses the latter revisions,
with an emphasis on the most notable changes, in general comparing how the “risk fee”
system operates both before and after the August 1, 2012 effective date of the Act.
Generally, the risk fee procedure is one in which a party desiring to drill a well to serve a
unit may (a) send out a Notice of Intent to drill a well to all other working interest owners in the
unit, (b) require each of those owners to commit to whether they will participate in the risk and
expense of the well, and (c) collect out of the non-participant’s share of unit production, not only
100% of the non-participant’s share of the cost of drilling, testing, completing, equipping and
operating the well, but also an additional “risk charge”, being a percentage (in the current statute
200%) of the costs of drilling, testing, and completing the well. The drilling party, however,
may not collect the risk charge from unleased owners.
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Which wells qualify?
Under the prior version of the statute, operators had to follow this procedure for unit
wells, including substitute unit wells. The statute did not expressly mention whether alternate
unit wells were included. The procedure was available only if there was no cost-sharing
agreement in place.
Now, the revised statute specifically provides that unit wells, substitute unit wells,
alternate unit wells, and cross-unit wells all may qualify for use of the procedure—although,
again, only if there is not a cost-sharing agreement in place.
What content is required in the Notice?
Under the old statute, the Notice which must be sent by the drilling party to activate the
risk fee procedure was required to include: (1) an estimate of cost of drilling, testing, completing
and equipping the proposed well; (2) the proposed location; (3) the proposed objective depth;
and (4) if the well had been drilled or was drilling, all non-public logs, core analysis, production
and well test data.
The revised statute still requires that those same items be included, but also specifies that
additional information must be included in the Notice, including a current authorization for
expenditure form, or AFE, that includes a “detailed” estimate of costs of drilling, testing,
completing and equipping the proposed well, and an estimate of unit ownership percentage of the
recipient.
When must the Notice be sent?
The prior statute contained no deadlines for sending the Notice. For various reasons, it
was advantageous for the drilling party to send the Notice as early as possible; further, the Notice
could always be reissued later if there was a need to correct omissions or erroneous names or
addresses of owners.
The revised statute appears to set a hard deadline for sending the Notice. The Notice is
now, apparently, required prior to the actually spudding of a well if the unit is in place on the
spud date. But if the unit was created during or after drilling, then the Notice is required to be
sent within 60 days of “date of the order” creating the unit. If the unit is revised to include an
additional tract or tracts after drilling, then the Notice is required to be sent within 60 days of
“date of the order” revising the unit. It is not clear whether the statute is referring to the date the
order was issued or the date the order was made effective, which is usually the hearing date,
which can be 30 or more days prior to the issuance date.
Because of this change, there is apparently no longer a chance for a drilling party to
correct errors or omissions after these deadlines have passed. If the initial Notice is improper or
late, then the drilling party may lose the ability to collect the risk charge.
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When must participating party pay to avoid risk charge?
Under the old statute, the participating party had to make payment within 60 days of
receipt of “detailed invoices” in order to avoid being deemed a nonparticipating party subject to
the risk charge. This likely meant that the drilling party could not require payment until 60 days
after it had sent third party invoices to the participating party.
Under the revised statute, the participating party is required to pay the drilling costs as
per the AFE within 60 days of spud in order to avoid being deemed a nonparticipating party
subject to the risk charge. Additionally, any “subsequent drilling, completion and operating
expenses” have to be paid within 60 days of receipt of subsequent detailed invoices.
What is the amount of the risk charge?
Under the prior version of the statute, the risk charge equaled 200% of drilling, testing
and completing costs for unit and substitute unit wells. Alternate and cross-unit wells were not
mentioned. This was in addition to the right to recoup 100% of drilling, testing, completing,
equipping and operating costs.
Under the revised statute, the risk charge remains at 200% of drilling, testing and
completing costs for unit and substitute unit wells. Act 743 sets the risk charge at 100% of
drilling, testing and completing costs for alternate unit wells. Cross-unit wells are specifically
mentioned by the Act 743 as well, and the risk charge depends on whether the cross-unit well is
a unit or substitute unit well (200%) or an alternate unit well (100%). Again, collection of these
risk charges is in addition to the right of the drilling party to recoup 100% of drilling, testing,
completing, equipping and operating costs.
Who is responsible for paying the royalty and overriding royalty burdens under the
nonparticipating owner’s lease during recoupment period?
Under the old statute, during the recoupment period, the nonparticipating party was solely
responsible for royalties created out of its working interest, and was required to make those
payments out of pocket, that is, without any reimbursement from the drilling owner. Drilling
parties had no liability to these royalty and overriding royalty owners if they were not co-owners
of the lease or co-assignors of the overriding royalty in question.
The nonparticipating party is still directly responsible to its royalty and overriding royalty
owners under the new statute. However, in a dramatic change, Act 743 provides that the
nonparticipating party is now “entitled to receive from the drilling owner…that portion of
production due to the lessor royalty owner under the terms of the contract or agreement creating
the royalty…” There is no limit on the royalty percentage for the base royalty due under this
new provision.
Similar new provisions of the statute apply to the overriding royalty due under the
nonparticipating owner’s lease; however, the overriding royalty payment due under the new
statute involves a somewhat complicated formula. Basically, the nonparticipating party is
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entitled to receive from the drilling owner its overriding royalty burdens, but only to the extent
that the sum of the nonparticipating owner’s base royalty and overriding royalty does not
exceed the drilling owner’s unit weighted average total royalty burden (base royalty and
overrides).
The nonparticipating party receives this payment “for the benefit of his lessor royalty
owner” and “for the benefit of the overriding royalty owner.” The amounts for the royalty and
overriding royalty are calculated based on the agreements “reflected of record at the time of the
well proposal.” These amounts are excluded from the revenue side of the equation in
determining when the drilling owner has fully recouped all costs recoverable under the statute.
What information regarding production must the drilling owner provide to the
nonparticipating owner?
Under the old statute this question was not addressed; the statute contained no specific
provisions for providing production data or proceeds of production other than what is reported to
the Office of Conservation.
Now, the revised statute provides that when the drilling owner delivers to the
nonparticipating owner “the share that is to be received,” the drilling owner must also provide all
the information that La. R.S. 31:212.31 requires a mineral lessee to provide its royalty owner
when making royalty payments.
During the recoupment period, what remedies are available to the royalty and overriding
royalty owners of the nonparticipating owner for nonpayment to them of their royalties?
The prior version of the statute did not specifically address this question. Royalty and
overriding owners had available to them special procedures in the Mineral Code which require
prior written notice, response or payment within 30 days, and consequences for failure (double
royalty penalty, attorney fees, interest, and in rare cases lease cancellation). But those special
procedures applied only as between these royalty or overriding royalty owners and the
nonparticipating owner.
Act 743 specifically incorporates those special Mineral Code non-payment procedures
into La. R.S. 30:10 to be applicable to royalties accruing during the recoupment period, but
specifically provides that the nonparticipating owner’s royalty and overriding royalty owners
have those same remedies not only against the nonparticipating owner, BUT ALSO AGAINST
THE DRILLING OWNER.
Because there is no contractual relationship between the nonparticipating owner’s
royalty/overriding royalty owners and the drilling party, there are significant uncertainties about
how this procedure will be applied. A specific provision of the statue prohibits a cause of action
against the drilling owner if he “provides sufficient proof of payment of the royalties to the
nonparticipating party.”
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During the recoupment period, what are the remedies available to the nonparticipating
owner for nonpayment to him by the drilling owner of the amounts required for the benefit
of his royalty and overriding royalty owners?
This is an entirely new provision because under the old statute no such payment was due.
Under the changes enacted by Act 743, if the nonparticipating owner pays his
royalty/overriding royalty owners, and the drilling party fails to pay the nonparticipating
owner the statutory amounts due, then a claim is made using a new special procedure.
Similar to the procedure available to an overriding royalty owner for nonpayment, this
new procedure requires prior written notice of nonpayment by the nonparticipating owner to the
drilling owner, and gives the drilling owner 30 days to pay or state a reasonable cause for
nonpayment. If he does neither, the court may award as damages double the royalty due, interest
and reasonable attorney’s fees.
If the nonparticipating owner has not paid his royalty/overriding royalty owners, and the
drilling party has not paid him, he likely can still make demand for payment on the drilling
owner and file suit to collect under the general law and procedures applicable for collection of
debts. He may be entitled to the same damages that any creditor generally may get in a suit to
collect monies due by statute or under a contract.
What are the rights/liabilities as between the drilling owner and a working interest owner
in the unit who has not been given a “risk fee” notice?
Under the prior statute the unnotified working interest owner could not be assessed a risk
charge, but the drilling owner could still recoup unit well costs from 100% of his production
before having to deliver production or proceeds to such a party. In addition, the unnotified
working interest owner had to pay his royalty and overriding royalty owners out-of-pocket.
The law remains the same in that it does not assess a risk charge to the unnotified owner.
And the drilling owner recoups his unit well costs from 100% of production less and except
royalties and overriding royalties (subject to some statutory limitations). But the statute now
requires the “participating owner” to deliver to the unnotified owner “the proceeds attributable to
his royalty and overriding royalty burdens as described in this Section.”
Note that the statute uses the term “participating owner” here instead of “drilling owner,”
which is used everywhere else in the statute; this variance in terminology may merely be an
insignificant oversight. The statute also uses the term “proceeds” here, rather than “portion of
production,” so the option of delivery in kind may not be available under this provision.
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May the drilling owner satisfy these new obligations to the nonparticipating party during
the recoupment period by delivery “in kind” to the nonparticipating party (or a third party
purchaser for his benefit) rather than payment of proceeds?
The drilling owner, more likely than not, will be able to satisfy its obligations during the
recoupment period by delivery in kind, but the language in different parts of the statute is
inconsistent as to this point.
Do any of these new provisions apply to existing wells, and if so, how?
The Legislature did not provide an effective date in the statute, meaning August 1, 2012
is the default effective date. Because this new statute makes a substantive change to the law—as
opposed to a procedural or interpretive change—it cannot be applied retroactively. But even if a
court were to determine that the changes were merely procedural or interpretive, a retroactive
application would still likely be found unconstitutional, as it would divest operators of vested
rights and/or impair previously existing contractual obligations.
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