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Interpretation of Depth Limitation Clauses in Mineral Transfers

Posted in Mineral Code

Ambiguous or conflicting property descriptions in conveyance instruments have been around as long as property conveyances have been made. With the radical increase in recent years of mineral production at deeper and deeper depths, the need for carefully describing what depths are being conveyed or reserved has become all the more important.  A lackadaisical attitude over such issues can lead to headaches down the line.

The Court in BRP LLC (Delaware) v. MC Louisiana Minerals LLC, 196 So.3d 37 (La. App. 2d Cir. 5/18/16) recently offered guidance on interpreting an ambiguous depth limitation clause found in a mineral transfer.  Often times when interpreting a depth limitation clause in a particular agreement, some basic knowledge of the geology of the region where the minerals at issue are located is helpful to fully understand the clause.  Further, new geologic structures capable of producing oil and/or gas can be discovered over time which may change the interpretation of such a clause or disclose an ambiguity in such a clause.

The BRP, LLC case involved a 2008 transfer of certain depths in approximately 13,000 acres from International Paper Company (“IP”) to Chesapeake Royalty, LLC and then a later transfer from IP of its remaining mineral rights to BRP, LLC.  A dispute arose between Chesapeake and BRP over which rights were conveyed to Chesapeake and which were reserved by IP.  BRP asserted that IP intended to transfer to Chesapeake its mineral rights only in the Haynesville Shale.  But Chesapeake claimed that it acquired from IP all the mineral rights below the Cotton Valley formation, thus including both the Bossier Shale and Haynesville formations.  BRP sued for a declaratory judgment that BRP owned the mineral rights in the Bossier Shale.  The Bossier Shale, according to the expert testimony presented in the case, exists between the Cotton Valley formation and the Louark Group, which in turn consists of the Haynesville and Smackover formations.  The expert testimony from geologists presented during the trial indicated that the productive portion of the Bossier Shale was the Bossier C Shale located in the middle to the lower portion of the structure.

In the Purchase and Sale Agreement between IP and Chesapeake, the mineral rights being transferred to Chesapeake were described in pertinent part as follows:

The “Assets” shall mean the following: all of Sellers’ right, title and interest in and to (a) the oil, gas and other minerals in, to and under the lands described in the attached Exhibit A, and any and all oil and gas leases covering such lands, INSOFAR AND ONLY INSOFAR as such oil, gas and other minerals are located below that depth which is the stratigraphic equivalent of the base of the Cotton Valley formation and the top of the Louark Group defined as correlative to a depth of 10,765’ in the Winchester Samuels 23 # 1 well (API # 1703124064) located in Section 23-14N-13W, DeSoto Parish, LA, and correlative to a depth of 9,298’ in the Tenneco Baker # 1 well (API # 1701320382) located in Section 12-16N-10W, Bienville Parish, LA

The ambiguity in the definition exists because the Bossier Shale is understood to exist between the Cotton Valley formation and the Louark Group. However, the description in the transfer does not recognize any formation between the Cotton Valley formation and the top of the Louark Group.  Chesapeake claimed to have known about the productive capability of the Bossier Shale at the time of the transfer while IP did not.

The lower court after hearing conflicting testimony from expert geologists on both sides and from the individuals on each side that negotiated the deal between IP and Chesapeake ruled in favor of Chesapeake. The trial court found that IP’s main intent in the depth limitation language was to reserve the Cotton Valley depths because of the shallow production it had established at those depths.  Further, the lower court noted that the correspondence between the parties during the negotiations appeared to focus on the Haynesville depths being transferred to Chesapeake.  Most importantly, the trial court found that the well depth footage markers contained in the depth limitation clause both denoted locations that were considered above the Bossier C Shale.  The well depth footage markers were given considerable weight by the trial court in the interpretation of which zones were reserved and conveyed in the transfer.

On appeal BRP argued that because the footage markers given in the description erroneously (mis)described the top of the Louark Group, the depth clause should be interpreted to convey all minerals below the lowest depth listed, which was the top of the Louark Group. The well depth footage markers given in the transfer created ambiguity because the markers denoted depths that were located within the Bossier Shale and that left several hundred feet of Bossier Shale between the well depth markers and the top of the Louark Group.  Thus, BRP contended that the only way to give effect to all depths given in the depth limitation clause was to set the depth at the deepest depth given, being the top of the Louark Group.  The effect of such an interpretation would be to reserve to the transferor not only the Cotton Valley formation, but also the Bossier Shale formation.

The appellate court rejected BRP’s position. It noted that the evidence presented at trial and the expert testimony given showed that interpretations about the location and composition of formations and groups may change over time and may be subject to disagreement by geologists.  The oil and gas industry has often handled this uncertainty by referencing specified stratigraphic markers such as the well depths rather than just by naming a particular formation.  The problem here was the instruments specified both wells depths and formation names.  Like the trial court, the appellate court found that the stratigraphic markers identified by well depths should control as the boundary line for the mineral rights conveyed.  This interpretation was supported by Chesapeake’s expert testimony, which the appellate court did not find manifestly erroneous.  Furthermore, the letter of intent executed by IP and Chesapeake clearly stated that the mineral rights being transferred fell below the Cotton Valley formation.

The lesson from this case is clear. To avoid ambiguities and competing interpretations of what depths are or are not included within a particular geologic formation, parties to a conveyance of depth-severed mineral interests should generally identify the boundary of any applicable depth severance by reference not to undefined geologic formations, but instead to specified, measured depths (for example the stratigraphic equivalent of a particular measured depth in a particular well, or a specified true vertical depth).  Where possible, avoid using just the name of a geologic formation as a boundary line—at least where the instrument does not also define for purposes of the instrument where the pertinent boundary of such formation is located.

Cynthia Nicholson Quoted in New Orleans CityBusiness

Posted in News

Cynthia Nicholson was quoted recently in the New Orleans CityBusiness article, “Offshore independents struggle with decommissioning requirements”.  The article pinpoints independent oil producers struggle to survive given the challenge of complying with new federal requirements to financially guarantee their costly responsibility to decommission offshore infrastructure after it is no longer useful and profitable.  Cynthia discusses the new rules and explains that “they’ve [BOEM] changed it to evaluate each company on its own merits.”

Protecting Operators Who Act In Reliance on an Order of the Commissioner of Conservation

Posted in Legal Updates, Louisiana Office of Conservation

The Commissioner of Conservation is the head of the Office of Conservation, a division of the Department of Natural Resources and the agency with primary regulatory responsibility for oil and gas operations in Louisiana.  As the Office of Conservation is a state agency, actions taken by the Commissioner are subject to the usual rules and procedures of administrative law.  Like many administrative statutes, the Conservation Act, Title 30, has its own set of administrative rules in La. R.S. 30:12, which is modeled, with some minor differences, after the comparable provisions of the Administrative Procedures Act.

One consequence of this regulatory scheme is fairly well-known—a unit order issued by the Commissioner may not be challenged for the first time in a lawsuit.  Instead, under the doctrines of exhaustion of remedies and primary jurisdiction, any challenge to an order of the Commissioner must be raised first in an administrative proceeding before the Commissioner.  Then, only if the Commissioner denies that challenge may the Commissioner’s order be appealed under La. R.S. 30:12 to a Louisiana district court in East Baton Rouge Parish.

A related consequence is less well-known but can be extremely useful and important for oil and gas operators—the collateral attack doctrine.  Under the collateral attack doctrine, a party may not indirectly, or “collaterally,” attack or otherwise call into a question a Commissioner’s order in litigation that is not an action for judicial review under La. R.S. 30:12.  Plaintiffs often attempt to evade the doctrines of exhaustion of remedies and primary jurisdiction by portraying their challenge as something other than a direct attack on an order of the Commissioner and by explicitly disclaiming any intent to challenge the Commissioner’s order.  For instance, a plaintiff may claim that it is challenging not the order but the operator’s violation of some other, independent obligation (such as that arising from a lease or other agreement) or that it is not challenging the order but instead is seeking only a declaration of the parties’ rights under, again, an independent source of obligations (such as a contract or statutory law).

The collateral attack doctrine prohibits such suits.  The prohibition against challenging an order of the Commissioner is not limited only to suits that would nullify or require a party to violate an order.  Instead, as the United States Fifth Circuit put it in Trahan v. Superior Oil Co., the doctrine “extends to suits between private parties in which a particular order of the Commissioner is an operative fact upon which the determination of the parties’ respective rights directly depends, even though all relief sought can be given, such as by money damages or lease cancellation”, for “Louisiana decisions clearly reflect the principle that suit under [La. R.S. 30:12] is the exclusive means by which an order of the Commissioner may be called into question in a judicial proceeding.”  700 F.2d 1004, 1014-16 (5th Cir. 1983).

Concretely, as the court put it in Vincent v. Hunt, this means that any suit that requires a court to do more than “accepting the Commissioner’s order as valid … simply reading the order itself, with no effort at interpretation,” is an impermissible collateral attack on an order of the Commissioner and must be dismissed.  221 So.2d 577 (La. App. 3 Cir. 1969).

The collateral attack doctrine provides important protection to oil and gas operators who act in reliance on an order of the Commissioner.  The Commissioner’s orders cannot be challenged either directly or obliquely.  So, an operator generally can act in reliance on such an order without fear of facing a later suit for having done so.

Finally, this protection extends not just to unit orders, but also, under the broad language of La. R.S. 30:12, to any action taken by the Commissioner.  However, it does not extend to actions taken by private parties under the Conservation Code, such as the formation of “voluntary units.”  This protection is an additional reason we generally counsel our operator clients to apply to the Commissioner for a “Commissioner’s unit” instead of relying on a privately formed voluntary unit.

Boustany Introduces “Ending Legacy Lawsuit Abuse Act”

Posted in Legal Updates

U.S. Rep. Charles Boustany has introduced the Ending Legacy Lawsuit Abuse Act (H.R. 6169), which is aimed at preventing forum-shopping by attorneys representing landowners in “legacy lawsuits” based on historical oil and gas operations.  The bill would amend the Federal Water Pollution Control Act to allow defendants to remove certain lawsuits implicating federal waters from state court to federal court.  Specifically, the bill provides that “[a]ny civil action filed in a State court that involves a claim of environmental contamination that impacts or threatens to impact any waters of the United States subject to the jurisdiction of the Corps of Engineers may be removed by the defendant to the United States district court for the district in which the civil action is pending.”  Senator David Vitter introduced a nearly identical bill in 2015; however, it stalled after being referred to the Committee on Environment and Public Works.

The scope of the new bill is somewhat unclear, as it does not define what constitutes “waters of the United States subject to the jurisdiction of the Corps of Engineers.”  The Army Corps’ regulatory jurisdiction is established by various federal laws, and is broadly defined to include “waters of the United States” for purposes of the Clean Water Act, as well as “navigable waters of the United States” under the Rivers and Harbors Act.  Last year, in response to U.S. Supreme Court decisions limiting the Army Corps’ jurisdiction, the Army Corps and the EPA published a joint rule that redefines and expands “waters of the United States” to include, inter alia, traditional navigable waters, interstate waters (including interstate wetlands), territorial seas, tributaries, isolated wetlands and “other waters” to be determined on a case-specific basis.  The rule has been met with numerous lawsuits, and the U.S. Sixth Circuit Court of Appeals has issued an order staying implementation of the new rule pending judicial review.  It appears that Boustany’s bill is designed to take advantage of the Army Corps’ recent attempts to enlarge its jurisdictional area, but in any event, the legislation looks to have broad applicability (particularly in south Louisiana) if it passes.

In a statement released last week, Boustany’s office discussed the purpose of the new legislation:

[Legacy] suits often name every oil and gas operator who ever worked at the site as defendants, often going back decades. Legislation was enacted to balance the rights of landowners with the requirement to clean up sites, however, some plaintiff lawyers circumvent these laws by venue-shopping in order to file claims in districts that are more friendly to legacy lawsuits. This results in many companies being forced to decide between an expensive settlement or enduring a lengthy trial process that hinders the company’s ability to address cleanup. Dr. Boustany’s bill will require any action filed in a state court that involves a claim of environmental contamination that impacts any waters of the United States to be heard in the district in which the civil action is pending.

Proponents of the legislation argue that coastal oil and gas activities affect national interests and are subject to myriad federal laws and regulations and thus that claims arising from these activities should be resolved by a federal court.  Many also argue that the removal of such claims to federal court is necessary to avoid the influence of state and local politics on the judicial process.  This sentiment was echoed by LOGA Vice President Gifford Briggs, who said that Boustany’s bill would effectuate the purpose of the federal Coastal Zone Management Act by balancing concerns regarding energy production and the environment:

Congressman Boustany’s bill is intended to recognize the original intent of the Coastal Management Act of 1972. One of Congress’ stated purposes for passing the CZMA was to promote our nation’s energy independence through responsible domestic energy production while balancing the nation’s interest in protecting our country’s wetlands. Both of these national interests are jeopardized by state and local lawsuits prosecuted in local venues under the guise of state and local coastal management programs. Our federal court system was created in large part to insure that the interests of our nation are not discarded in favor of local politics and financial gains at the expense of our national resources.

Boustany’s bill represents a welcome proposal for oil and gas companies facing an onslaught of environmental litigation throughout Louisiana.  Defendants in legacy lawsuits may soon have a valuable tool to counteract forum-shopping by plaintiffs’ attorneys looking for an advantage.  Gordon Arata is monitoring the status of the legislation and will provide updates as the bill moves through the legislative process.

Governor Edwards and Attorney General Landry Still at Loggerheads Over Potential Oil and Gas Lawsuits

Posted in Legal Updates

The internal tussle between Louisiana’s governor and attorney general over potential lawsuits against the oil and gas industry continues to rage.  On September 21, 2016, Governor John Bel Edwards reaffirmed that he continues to be in conflict with Attorney General Jeff Landry over the governor’s desire to sue the oil and gas industry for its alleged role in coastal land loss.  Before Governor Edwards took office in January, Plaquemines, Jefferson, and Cameron Parishes sued oil and gas companies in state courts alleging that dredging and other historical oil and gas operations have damaged Louisiana’s coastal zone.  The District Attorney for Vermilion Parish, Keith Stutes, filed a fourth such lawsuit on behalf of Vermilion Parish earlier this year.  Governor Edwards is now urging coastal parishes to initiate additional lawsuits within the next 30 days, informing them that if they don’t, the state will do so on their behalf.

In several public releases, Governor Edwards stated that his attempts to reach a settlement with the oil companies were to no avail and that he is therefore moving forward with litigation.  Although he expects other parishes to file suits, the governor has said the state will pursue its own litigation “in the not-too-distant future” should the parishes fail to do so.  While not opposing such litigation outright, Attorney General Landry has taken the position that, before the state can file suit, it is required to complete an administrative process with the Department of Natural Resources.  Landry is imploring Governor Edwards to utilize this process first.

In addition, Landry has raised concerns about the private counsel Governor Edwards wishes to retain for these proposed lawsuits.  As attorney general, Landry must approve all outside counsel retained by the state.  Landry believes that the proposed contract with Taylor Townsend, the head of Edwards’ political action committee, could potentially pay to him and other subcontracted parties attorneys’ fees beyond the hourly rates permitted by state statute and may also run afoul of Louisiana’s Ethics Code.  Landry has stated that he would approve the outside counsel so long as the contracts comply with the law and so long as his office is permitted to take the lead in representing the state.  The Louisiana Oil and Gas Association and the Louisiana Mid-Continent Oil and Gas Association released a joint statement criticizing Governor Edwards’ actions, claiming that the governor “is doubling down on a this flawed attempt to hire private lawyers to attack Louisiana’s energy industry.”

In response, Governor Edwards has rejected Landry’s criticism and insinuations of cronyism, stating that Landry either “doesn’t understand the contract or he is purposefully misrepresenting it” and that there is nothing untoward about the payment structure of outside counsel.  Governor Edwards also dismissed much of the criticism as an attempt by the oil and gas industry to control who represents the state in litigation against the industry.

With neither Governor Edwards nor Attorney General Landry ceding any ground, it appears more and more likely that the courts will have to resolve their squabble.  Although these issues engender uncertainty, it is likely that oil and gas companies will eventually face lawsuits by the state for coastal erosion.  It would be prudent for these companies to get their ducks in a row now and prepare for the long battles ahead.

PHSMA Proposes New Regulations for Transporting Hazardous Materials

Posted in Legal Updates

On April 1, 2016, I wrote about new legislation revamping federal energy pipeline rules and reauthorizing the Pipeline and Hazardous Materials Safety Administration (PHSMA), the federal agency that oversees pipeline safety.  The legislation was ushered through the Congress with bipartisan support and a sense of urgency from numerous congressmen who felt that new regulations in this area were critical in the wake of the Aliso Canyon incident; even industry groups agreed that this was an area where more federal oversight and regulations were necessary.  Consistent with its mandate, PHSMA recently issued a notice of proposed rulemaking creating changes to what qualifies as proper shipping names, hazard classes, packing groups, special provisions, packaging authorizations, air transport quantity limitations, and vessel stowage requirements for the transport of hazardous materials entering into international trade.  These proposed rule changes are based on recent revisions to the U.N. Model Regulations, the International Maritime Dangerous Goods Code, and the International Civil Aviation Organization’s Technical Instructions for the Safe Transport of Dangerous Goods by Air.

In its notice, PHSMA explained that these changes are intended to “enhance transportation safety resulting from the consistency of domestic and international hazard communication and continued access to foreign markets by U.S. manufacturers of hazardous materials.”  It also noted its belief that these revisions would “result in cost savings and will ease the regulatory compliance burden for shippers engaged in domestic and international commerce, including trans-border shipments within North America.”  The public has 60 days to file comments to the proposed regulations.  If ultimately adopted as proposed, the regulations will take effect January 1, 2017.

These proposed regulations were preceded by other recommendations from PHSMA to regulate trains that carry highly flammable cargo like crude oil.  The intent of these proposed regulations is to improve spill response and readiness in order to mitigate the fallout from any potential accidents.  One part of these regulations would require railroads to share information with state and tribal emergency response commissions to improve overall preparedness for an accident.  These are all welcome changes for facilitating a safe and profitable energy market.

In a time of increasing polarization, it’s encouraging to see at least one area where lawmakers have come together to enact legislation that addresses a real problem.  As of now, it appears that PHSMA is tackling its task in earnest and trying to update an old regulatory regime that was ill-equipped to address today’s problems.  Let’s all hope that this type of cooperation and pragmatism catches on.

Legislature Establishes New Requirement for Changing the Operator of a Well

Posted in Louisiana Office of Conservation

By Act No. 342 of its 2016 Regular Session, the Louisiana Legislature amended La. R.S. 30:28, which addresses the issuance of drilling permits, by adding a new subsection J.  Under this new La. R.S. 30:28(J) and effective August 1, 2016, no later than 30 days after the issuance of an amended permit to transfer a well to another operator, an operator is required to identify on a form approved by the Commissioner of Conservation the surface owner of lands on which the well site is located.  Surface owner is defined as the person shown in the assessor’s rolls of the parish as the current owner of the surface rights for the land on which the well site is located.

Before La. R.S. 30:28(J) was enacted, the new operator of the well was only required to submit a Form MD-10-R-A (also known as the pink card) or, if multiple wells were being transferred to a new operator, a Form MD-10-R-AO (also known as the blue card).  For a change of operatorship submitted on or after August 1, 2016, the operator must submit—in addition to the MD-10-R-A form or MD-10-R-AO form, whichever applies–the new form SOCI.  Note that a separate form SOCI is required per surface owner.  In the case of multiple wells being transferred, all of the wells must be listed on a form SOCI.  Curiously, neither the Legislature nor the Office of Conservation requires an operator to identify any surface owners in submitting an initial permit for a well; thus, at this time, if operatorship never changes, no filings relating to surface ownership are required.

If you have any questions about changing the operator of a well, please do not hesitate to contact us.

Certain Legal Deadlines Suspended in Louisiana Due to Flooding

Posted in Legal Updates, News

In the wake of the devastating floods that have affected south Louisiana, the State of Louisiana and the federal district courts in Louisiana have suspended certain legal deadlines.

Following his declaration of a state of emergency, Governor John Bel Edwards signed an amended Executive Order on August 17, 2016 (amending a previous executive order of August 15, 2016 and applying retroactively from August 12, 2016) suspending legal deadlines as follows:

  • Liberative prescription and peremptive periods are suspended throughout the State of Louisiana until September 9, 2016.
  • Deadlines in legal proceedings in courts, administrative agencies and boards in the following parishes are suspended until September 9, 2016: Acadia, Ascension, Assumption, Avoyelles, Cameron, East Baton Rouge, East Feliciana, Evangeline, Iberia, Iberville, Jefferson Davis, Lafayette, Livingston, Pointe Coupee, St. Charles, St. Helena, St. James, St. John the Baptist, St. Landry, St. Martin, St. Tammany, Tangipahoa, Vermilion, Washington, West Baton Rouge and West Feliciana.
  • Deadlines in legal proceedings in courts, administrative agencies and boards in all other parishes were suspended from August 12, 2016 through August 19, 2016. However, if a party to a pending matter can show that there is an inability to meet legal deadlines caused by the flooding, then deadlines for that specific matter are to be suspended until September 9, 2016.

The executive order specifies that courts, administrative agencies and boards within the listed parishes should use due diligence in communicating with attorneys, parties and the public on how the executive order will be implemented and interpreted.  Further, the executive order states that the suspensions of deadlines in legal proceedings is not to be interpreted to prohibit an owner of immovable property from reclaiming leased property if abandoned as provided by law or from entering leased property to make necessary repairs as provided by law.  The executive order is effective through September 9, 2016, unless amended, modified, terminated or rescinded by the Governor, or terminated by operation of law before that time.

In addition, the United States District Courts for the Eastern District, the Middle District and the Western District of Louisiana have issued orders relating to legal deadlines in those courts as a result of the flooding.

We recommend that you contact your Gordon Arata attorney if you have any questions about how these state or federal suspensions of deadlines may affect you or your company.

Lease Division in Louisiana – “The Times They Are A-Changin’”

Posted in Louisiana Mineral Code

Under the Louisiana Mineral Code and caselaw, a mineral lease is generally not divisible by assignment.  Nonetheless, courts have long held that a lease contract can be rendered divisible if it contains certain language.  The consequences of the interpretation of this language are of critical importance for oil and gas lessees and their successors and assigns in the context of lease maintenance.  This article examines and reviews some of the earlier cases on the issue and compares them to some more recent cases that are in tension, and perhaps even overrule, these earlier cases.

One of the earliest notable cases on lease division by assignment is Swope v. Holmes, 169 La. 17, 124 So. 131 (1929).  On March 17, 1925, Swope leased approximately 2500 acres of land to McCurry. By mesne conveyances, Holmes became the sole owner of the mineral lease insofar as it affected approximately 440 acres.  The chief reason urged for partial cancellation of the lease was the non-exploration and non-development of some 400 of the relevant 440 acre tract.  The lease contract contained the following provision:

It is hereby agreed in the event this lease shall be assigned as to part or as to parts of the above described lands, and the assignee or assignees of such part or parts shall fail or make default in the payment of the proportionate part of the rents due from him or them, such default shall not operate to defeat or affect this lease in so far as it covers a part or parts of said lands upon which said lessee or assignee thereof shall make due payment of said rental.

The Supreme Court of Louisiana held that the lease was divisible based on the above quoted language, and upheld partial cancellation of the lease.

In Roberson v. Pioneer Gas Co., 173 La. 313, 137 So. 46 (1931), the lessors filed suit to declare an oil and gas lease expired as to 85 of the 125 acres of land leased.  The district court granted judgment for the lessors; and the defendant appealed.  The lease covered 125 acres and was assigned to Pioneer Gas Company, which later assigned the lease to George D. Pipes and W. T. Mack only insofar as it covered 40 acres.  Before the primary term expired, Pipes and Mack completed a profitable gas well on the 40 acres assigned to them.  The well continued to produce in paying quantities and up through at the time of the trial of the case.  But no well was drilled or attempted to be drilled on the 85 remaining acres of land that Pioneer retained.  Just after the primary term expired, the lessors sued Pioneer for partial cancellation of the lease.  Pioneer argued that the gas drilled by Pipes and Mack on their 40 acres kept the entire lease in force including for the remaining 85 acres that Pioneer retained.  The relevant assignment provision in the lease read as follows:

[I]t is hereby agreed in the event this lease shall be assigned as to part or as to parts of the above described lands, and the assignee or assignees of such part or parts shall fail or make default in the payment of the proportionate part of the rents due from him or them, such default shall not operate to defeat or affect this lease in so far as it covers a part or parts of said land upon which said lessee or assignee thereof shall make due payment of said rental.

The district court ruled that the effect of the assignment of the 40 acres to Pipes and Mack was to divide the original lease into two leases, by making a separate lease between the plaintiffs, as lessors, and Pipes and Mack, as their lessees, under the terms and conditions stipulated in the original lease.  What Pipes and Mack did, or failed to do, to keep the lease in force on their 40 acres could not affect the lease as to the remaining 85 acres of land that Pioneer retained.  Relying on this same lease language, the Supreme Court of Louisiana affirmed and thus upheld partial cancellation of the lease as to Pioneer’s 85 acres.

A review of two recent decisions on this issue, specifically Hoover Tree Farm, L.L.C. v. Goodrich Petroleum Co., L.L.C. in 2011 and Guy v Empress, L.L.C. in 2016, suggest that, at least insofar as geologic lease division is concerned, Louisiana courts—or at least courts in the Louisiana Second Circuit—are not so inclined to follow these decisions of the past.

In Guy v. Empress, L.L.C., 50,404 (La. App. 2 Cir. 4/8/16), 193 So. 3d 177, reh’g denied (May 12, 2016), the plaintiffs, owners of a 140–acre tract, and defendant Long Petroleum, L.L.C. entered into a mineral lease on March 23, 2004, with a primary term that was extended to March 23, 2009. The lease included a typical habendum clause and continuous drilling provision for maintaining the lease without a 90-day gap in production or operations and also included both horizontal and vertical Pugh clauses as well as the following provision regarding assignment of the lease:

[I]f Less[ee] or assignee of part or parts hereof shall fail to comply with any other provisions of the lease, such default shall not affect this lease insofar as it covers a part of said lands upon which Lessee or any assignee shall comply with the provisions of the lease.

In an assignment to Empress, L.L.C., Long retained the “shallow rights” in the lease, while conveying the “deep rights.”  More specifically, the assignment provided that it was a conveyance, assignment and transfer of “[a]ll of Assignor’s right, title, and interest in and to all oil gas leases and subleases and further including working interests, mineral interests, royalty interests, rights of assignment and reassignment, net revenue interests and undeveloped locations under or in oil, gas or mineral leases and interest in rights to explore for and produce oil, gas and other minerals[,]save and except” the formations and depths between the surface and the base of the Cotton Valley formation (the “shallow rights”).

Before the primary term of the lease expired, Long entered into an Operating Agreement with Pinnacle, which spud a Hosston well in the “shallow rights” before the expiration of the primary term and thereafter successfully completed the well, which produced until December 31, 2011.  As to the “deep rights,” preparatory activities for the drilling of the Yarbrough No. 1 well commenced on August 10, 2009 (months after expiration of the primary term); the well was spud in September 2009 and then completed with continuous production thereafter.

The lessors argued that the partial assignment from Long to Empress divided the Lease into two separate and independent leases.  Specifically, they argued that the deep rights expired on March 23, 2009 since the Yarbrough No. 1 was not spud until after expiration of the primary term and that, as to the shallow rights, since the Edwards No. 1 ceased production on December 31, 2011, and thereafter, no drilling, reworking or other operation was undertaken for the shallow rights, the entire lease terminated as of that date.

The Court of Appeal in Louisiana concluded first that the original lessee’s assignment of the deep rights did not divide the lease into two separate leases and second that the lessee and its assigns timely drilled and produced from both shallow and deep formations within the time required by the habendum clause without a 90 day gap.  The court explained that the Edwards No. 1 continued in production until December 31, 2011, by which time the Yarbrough No. 1 had been drilled and was producing.  Therefore, on March 23, 2009—the date upon which the primary term would have expired—defendants were “engaged in operations for drilling, completion or reworking, or [in] operations to achieve or restore production, with no cessation between operations or between such cessation of production and additional operations of more than ninety (90) consecutive days.”

The Supreme Court reached a similar result in Hoover Tree Farm, L.L.C. v. Goodrich Petroleum Co., 2011-1225 (La. 9/23/11), 69 So. 3d 1161.  In Hoover Tree Farm, a lessor sued its original lessee and a transferee to enforce a favored nations provision in the lease.  The lease agreement between the plaintiff, Hoover Tree Farm, and its original lessee, Petroleo, as agent for Goodrich Petroleum Co., included a provision guaranteeing that as to the “Lease Area”  no lessor of either lessee or Goodrich or their successors and assigns shall recieve a higher bonus and/or royalty than lessor.  Thereafter, Goodrich transferred an undivided 50% of its interest in the lease to Chesapeake Louisiana, LP limited as to depths below the Cotton Valley formation.  After the agreement with Goodrich, Chesapeake obtained oil and gas leases of lands located within the “Lease Area” paying bonuses and royalties higher than what Goodrich paid to plaintiff.  Plaintiff filed suit against Goodrich and Chesapeake seeking to enforce the favored nations provision.

The Hoover Tree Farm court analyzed in great detail the difference between a sublease and an assignment and the related Mineral Code articles. The relevant assignment provision in the lease mirrored the lease assignment language in Empress.  The court pointed to the allusion to geographic rights in the assignment language as distinguishing from the other line of cases on the issue, “the specific assignment of rights which this default provision addresses concerns the assignment to another of all rights of the lessee in a particular geographical area of the Lease.”  And without expounding on the distinction, the court found that the lease assignment did not divide the lease.

So what does this mean for lessees and lessors, when the longstanding interpretation of a simple assignment provision in a contract appears to have suddenly been turned on its head?  Perhaps it means that things are as they should be.  In the words of Bob Dylan: “Keep your eyes wide- The chance won’t come again- And don’t speak too soon-For the wheel’s still in spin-And there’s no tellin’ who- That it’s namin’- For the loser now- Will be later to win- For the times they are a-changin’.”  Be aware of the distinctions that may be read into these assignment provisions should litigious issues arise, and be diligent in drafting these contract provisions.  As our industry and all the things that go along with it develop, progress and advance, so will our judges and their analysis and interpretation of the meaning and intent of the parties to a contract involving these ever-changing issues.

Amendment to Louisiana Risk Fee Statute Closes Loophole Shown by Recent Case

Posted in Legal Updates

Louisiana Revised Statute 30:10, commonly referred to as the Risk Fee Statute, was amended during the 2016 Regular Session of the Louisiana Legislature.  The statute as amended took effect June 13, 2016.  The amendment expressly allows an operator of a commissioner’s unit to assert the risk fee penalty against a non-operator lessee by sending the required notice under the Risk Fee Statute after the spudding of the well.  This article is limited to discussing only the 2016 amendment to the Risk Fee Statute and how it closed a loophole illustrated by a recent case addressing a prior version of the statute.  For prior discussions of other particulars of the Louisiana Risk Fee Statute, see our prior blog and paper.

As background, the Risk Fee Statute was also amended previously in 2012.  The 2012 amendment to the Risk Fee Statute required the risk fee notices to be sent before the spudding of a well.  The pre-2012 amendment version of the statute required an operator to send the risk fee notices to non-operator lessees before the completion of the well.  The potential loophole created by this requirement was illustrated in the recent case of TDX Energy, LLC v. Chesapeake Operating, Inc., 2016 WL 1179206, which was decided under the pre-2012 version of the Risk Fee Statute.

In the TDX case, TDX Energy, LLC acquired several leases in a Haynesville unit operated by Chesapeake Operating, Inc.  The unit order was dated effective September 16, 2008 and the unit well was spud on February 5, 2011 and completed on July 19, 2011.  TDX acquired its leases from Touchstone Energy, LLC on October 25, 2011.  The leases were taken by Touchstone between July 18, 2011 and September 14, 2011 but were dated July 15, 2011 and were not recorded until between July 22, 2011 and September 14, 2011 and thus after Chesapeake had completed the unit well.  Remember that under the pre-2012 version the risk fee notices were required to be sent to non-operator lessees prior to the completion of the unit well.  However, in the TDX case the leases acquired by TDX were not recorded in the parish conveyance records until after the well was completed.  In fact, Chesapeake was not aware of the TDX leases until TDX sent it a request for a report on the well in accordance with La. R.S. 30:103.1 and 30:103.2 on December 5, 2011.  Chesapeake responded by letter dated January 23, 2012 and provided the well costs and invoked the Risk Fee Statute to give TDX 30 days from the date of the risk fee notice to elect whether to participate in the well.

Thereafter, TDX sued Chesapeake in Louisiana federal court to recover production payments, accounting, penalties, and attorney’s fees under La. R.S. 30:103.1 and 30:103.2.  In response, Chesapeake filed a counterclaim seeking a declaration that pursuant to the Risk Fee Statute it was entitled to recover out of the production from the unit well not only the expenses incurred in drilling, testing, completing, equipping and operating the well, including a charge for supervision, allocable to the tracts covered by the TDX leases, but also a risk charge equal to 200% of those costs.

The court ruled that Chesapeake was entitled to own and recover out of production from the unit well TDX’s allocated share of the actual reasonable expenditures incurred in drilling, testing, completing, equipping and operating the unit well, including a charge for supervision.  In fact, TDX did not dispute that Chesapeake was entitled to these well costs.

But the court also ruled that Chesapeake could not recover a risk fee penalty against TDX because the pre-2012 version of the Risk Fee Statute called for the risk fee notice to be sent before the completion of the well with few exceptions, which were not applicable to the facts of the TDX case, i.e., changing the size and/or shape of a unit after the unit well had been completed.  The court recognized the policy behind the Risk Fee Statute was to get rid of the free-rider problem of a non-operator sitting back and waiting until after a well was drilled before deciding to participate in the well.  However, here, the Risk Fee Statute failed to accomplish this goal.  Nonetheless, the Court stated that its hands were tied by the plain language of the statute.  As a result, TDX was able to avoid having the risk fee charged against it by not recording the leases it acquired until after the completion of the well, thereby avoiding letting Chesapeake learn of its interest as a non-operator leaseholder.  The court also reaffirmed the fact that the risk fee cannot be asserted against an unleased mineral owner.  Therefore, there would have been no reason for Chesapeake to risk fee notice the mineral owners before the TDX leases were recorded.

The TDX case shows the loophole that existed in the pre-2012 version of the Risk Fee Statute (and also the version that existed after the 2012 amendment).  Under both prior versions of the Risk Fee Statute, a non-operator lessee could avoid having to bear a risk fee penalty simply by waiting to record its leases until after the unit well at issue was completed (pre-2012) or spud (after 2012 amendment).  That way, any risk fee notice sent by the operator of a unit well to that non-operator lessee would be untimely and, therefore, the risk fee of 200% for a unit well for well costs could not be charged.

Act No. 524, which became effective June 13, 2016, amended La. R.S. 30:10 to allow the operator of a unit well to send the required risk fee notices after a well was spud or even completed.  By allowing for the notice to be sent after a well has been completed, the loophole in the Risk Fee Statute as demonstrated by TDX appears to have been closed.  Therefore, it appears that if TDX were decided under the current version of the Risk Fee Statute, then Chesapeake would have been allowed to assert the risk fee charge against the non-operator lessee.

The 2016 amendment to the Risk Fee Statute makes several other changes to the language and procedures outlined under the statute to allow for the risk fee notice to be sent after completion of a well.  Specifically, the payment of estimated drilling costs by a non-operator lessee is now deemed timely if received by the operator within 60 days of the actual spudding of the well or within 60 days of the receipt by the notified non-operator lessee of the notice of AFE costs, whichever is later.  The prior version of the Risk Fee Statute required the payment to be received within 60 days of the spudding of the well or within 60 days from the receipt of subsequent detailed invoices for subsequent costs incurred after the spudding of the well.  Additionally, the requirement under the prior version of the Risk Fee Statute for notices to be sent within 60 days of the date of a unit order to non-operator lessees in a unit where there is located a well already drilled or drilling (post-drill unitizations) or within 60 days of a unit order to any additional non-operator lessees included in a revised unit has been eliminated.  Again, these changes to the Risk Fee Statute have the effect of allowing an operator to send a risk fee notice to a non-operator lessee after the spudding and completion of a well.

Of additional note, the 2016 amendment to the Risk Fee Statute clarifies that an operator’s failure to provide a risk fee notice to one non-operator lessee will not affect the validity of a risk fee notice being properly provided to any other non-operator lessee.  Thus, a non-operator lessee who receives a risk fee notice cannot attack the validity of that notice by arguing that someone did not timely receive a proper notice. The prior version of the Risk Fee Statute did not directly address this issue.

If you should have any questions concerning the application of the Risk Fee Statute in Louisiana, please do not hesitate to give us a call.