Recently in Recent Cases Category

June 26, 2014

Amarillo Court of Appeals Refuses to Apply Accommodation Doctrine to Groundwater

Last week, the Amarillo Court of Appeals issued its opinion inn City of Lubbock v. Coyote Lake Ranch, LLC, No. 07-14-00006-CV, holding that the accommodation doctrine did not apply to restrict the City's use of Coyote's land to develop the City's groundwater under the land.

In 1953, the City of Lubbock bought the rights to groundwater under the land now owned by Coyote Lake Ranch. In that deed, the City acquired all groundwater rights, and "the full and exclusive rights of ingress and egress in, over and on said lands so that the Grantee of said water rights may at any time and location drill water wells and test wells on said lands for the purpose of investigating, exploring, producing, and getting access to percolating and underground water." The deed granted the right to lay water lines, build reservoirs, booster stations, houses for employees, and roads, "together with the rights to use all that part of said lands necessary or incidental to the taking of percolating and underground water and the production, treating and transmission of water therefrom and delivery of said water to the water system of the City of Lubbock only."

In 2012, the City proposed a well field plan for the property and began testing and development under that plan. Coyote sued, asking for a temporary injunction to halt the City's activity. Coyote claimed that the City failed to accommodate Coyote's existing uses of the property (the opinion does not say what those uses are), and that the City could use alternatives that would lessen damage to Coyote's use of the land. The trial court granted the temporary injunction, holding that Coyote was likely to be able to show at trial that the City's plan could be "accomplished through reasonable alternative means that do not unreasonably interfere with [Coyote's] current uses." The City appealed from that order.

In the Court of Appeals, the City made two arguments: first, it argued that the accommodation doctrine does not apply to the relationship between the owner of the surface and the owner of groundwater. Second, it argued that the express language in the water rights deed would prevail over general accommodation doctrine principles.

The Court of Appeals reversed, agreeing with the City that the accommodation doctrine does not apply to limit the rights of holders of groundwater rights. The Court said that the Texas Supreme Court has not extended the accommodation doctrine to groundwater, and that "changes in the law should be left to the Texas Supreme Court or the Texas Legislature."

The accommodation doctrine was developed to ameliorate the harsh results of the rule that the mineral estate is the dominant estate and mineral owners have the right to use as much of the surface of the land as is reasonably necessary to explore for and extract minerals, without compensation to the surface owner. The doctrine requires the mineral owner to accommodate existing surface uses where that can be done using established industry practices. The Court's opinion does not provide any logical reason why the accommodation doctrine should not apply also to severed groundwater rights. Indeed, the City's use of Coyote's land to develop its groundwater might be more intrusive than would surface use for development of mineral rights under the land.

The opinion does not address the City's second argument, that the express language in its deed granting the City extensive rights to surface use should make the accommodation doctrine inapplicable. Many deeds granting or reserving mineral interests contain express language granting the mineral owner the right to use the surface estate for oil and gas exploration and development. I have not seen a case involving the accommodation doctrine in which the mineral owner contended that the express language in its deed granting access rights prevailed over the accommodation doctrine.

Severance of groundwater from the surface estate is not as common in Texas as severances of minerals. But with increased demands for and value of groundwater, such severances will become more common, and other conflicts between the surface owner and the owner of groundwater will likely arise. I expect that the Texas Supreme Court will have to address the applicability of the accommodation doctrine to severed groundwater rights in the near future.

June 23, 2014

Texas Supreme Court Decides Key Operating v. Hegar

The Texas Supreme Court last week decided Key Operating & Equipment, Inc. v. Hegar, No. 13-0156, reversing the courts below and holding that Key Operating has the right to use a road crossing Hegar's tract to produce from a well on adjacent lands.

The legal principle the Court applied is not surprising and did not substantially change existing precedent. But the unusual facts of the case illustrate how far the Court will go to protect the rights of mineral lessees when those rights conflict with interests of the surface owner.

The legal precedent the Court followed is this:  when two tracts are combined to create a pooled unit, the operator of the unit has the right to use the surface of all of the land covered by the leases included in the unit to operate wells located anywhere on the unit, regardless of the location of the well.

The facts of the case are these:  Hegar bought 85 acres of land in 2002, and built a house there in 2004. The 85 acres was originally part of a 191-acre tract, the Curbo/Rosenbaum tract.  When the Hegars bought the land, 1/8th of the minerals under the Curbo/Rosenbaum tract were owned by the owners of Key Operating, who had leased the mineral interest to Key Operating. Key had a well on an adjacent tract, the Richardson #1, and had created a pooled unit including 10 acres of the Curbo/Rosenbaum tract and 30 acres of the Richardson tract. An existing road crossed the Hegar land and led to the Richardson #1. After the Hegars built their home, Key Operating drilled another well on the pooled unit, the Richardson #4, and traffic on the road increased substantially. The Hegars filed suit, arguing that Key had no right to "access or use the surface of the Hegar Tract in order to produce minerals from the Richardson Tract."  At trial, the Hegars produced expert testimony that the Richardson #4 Well was draining only 3 1/2 acres, and that the well's drainage area did not reach the Hegars' property and was not draining the Hegars' property. The trial court held that Key did not have the right to use the road across the Hegars' property to produce from a well that was not actually draining their property. The court of appeals affirmed. 403 S.W.3d 318 (Tex.App.--Houston [1st Dist] 2013).

The facts recited in the opinion reveal that Key appears to have created the pooled unit primarily if not solely to preserve its right to use the existing road to get to the Richardson #1 well. Key's owners apparently bought 1/8th of the minerals under the Curbo/Rosenbaum tract so that they could lease the interest to their own company and create the pooled unit. The opinion does not say for sure, but Key apparently pooled its lease of the 1/8th mineral interest in 10 acres from the Curbo/Rosenbaum tract even though it had no lease on the other 7/8ths of the minerals in that 10 acres. Because the new well, the Richardson #4, was not draining the Curbo/Rosenbaum tract, there was apparently no geological reason to create the pooled unit.

Even so, the Supreme Court held that, once the pooled unit was formed, Key had the right to use the Curbo/Rosenbaum tract to produce from wells on the pooled unit. The court held that

once pooling occurred, the pooled parts of the Richardson and Hegar Tracts no longer maintained separate identities insofar as where production from the pooled interests was located. So the legal consequence of production from the pooled part of the Richardson Tract is that it is also production from the pooled part of the Hegar Tract, and the Hegars do not contend that Key did not have the right to use the road to produce minerals from their acreage. Because production from the pooled part of the Richardson Tract was legally also production from the pooled part of the Hegar tract, Key had the right to use the road to access the pooled part of the Richardson tract.

So the Hegars will have to put up with the road and the traffic. They are bound by the legal fiction, found to be untrue as a matter of fact, that production from the pooled part of the Richardson tract was "legally" production from the their tract, thus giving Key the right to use its road.

A footnote in the Supreme Court's opinion raises an interesting question: "The Hegars do not argue that the Richardson lease does not grant the right to pool or that the pooling was in bad faith."  Clearly, the mineral owners under the Richardson tract could complain that the pooling of their lease with 10 acres of the Curbo/Rosenbaum tract was in bad faith because the Richardson #4 was not in fact draining the Curbo/Rosenbaum tract. But would the Hegars, who apparently had no mineral interest in their tract and no right to share in production from the unit, have standing to argue that the pooled unit was created in bad faith? The court does not say, but the footnote implies as much.

May 28, 2014

A Second Nuisance Verdict in Barnett Shale

A jury has awarded damages in a second nuisance case against an operator, this time against Chesapeake Energy.  In Crowder et al. v. Chesapeake Operating Inc., case number 2011-008169-3, in Tarrant County Court at Law, the jury awarded the Crowders $20,000 for what the jury found to be a temporary nuisance - drilling operations conducted by Chesapeake in a field behind their house, where Chesapeake has drilled 13 wells. The Crowders complained of offensive odors and extensive noise. The jury failed to find that Chesapeake's operations created a permanent nuisance, which would have entitled the Crowders to additional damages. The Crowders filed their suit in 2011.

While the jury award in Crowder will not excite plaintiffs' attorneys to look for additional such cases -- unlike the $2.9 million verdict recently awarded in another case, Lisa Parr v. Aruba Petroleum, Cause No. 11-01650-E, in the County Court at Law No. 5 of Dallas County -- the case does show the viability of nuisance claims aimed at oil and gas operations near residences, especially in urban areas.

The Dallas city council recently adopted a drilling ordinance prohibiting well locations within 1,500 feet of any residence, effectively prohibiting most drilling within the city limits. The setback in Fort Worth is 600 feet. There are more than 1,700 wells in the City of Fort Worth.

May 5, 2014

Texas Supreme Court Agrees to Hear Hooks v. Samson

The Texas Supreme Court has granted the plaintiffs' petition to review a case important for Texas mineral owners, Hooks v. Samson Lone Star. I wrote about this case when it was decided by the Houston First Court of Appeals in 2011. The court of appeals' opinion reversed a judgment for $21 million against Samson Lone Star in a case involving alleged bad-faith pooling and fraudulent misrepresentations by the Hooks' lessee. The court of appeals threw out the judgment, holding that Texas Supreme Court precedent required it to hold that the Hooks' claims were barred by the applicable statute of limitations.

The statute of limitations bars claims if they are not filed within four years (or two years for some claims) of the event that caused the damages or injury for which the claim is brought. In some cases, courts have excused the delay in filing claims if the damage or injury was not discovered until a later date. Under this "discovery rule," the statute of limitation is "tolled" until the plaintiff discovered or, with reasonable diligence, should have discovered, her injury. Also, courts have held that the statute of limitations is tolled where the defendant fraudulently conceals the facts giving rise to the damage or injury.

Over the last several years, the Supreme Court has severely narrowed the circumstances under which plaintiffs can invoke the discovery rule or claim fraudulent concealment to toll limitations on a claim, particularly in suits by mineral owners against their lessees. In Exxon v. Emerald in 2009, the Supreme Court reversed an $18 million judgment against Exxon on the basis that the mineral owners' claims were barred by limitations -- despite an express finding by the jury that the plaintiffs had filed their claim within four years after they discovered or should have discovered Exxon's fraudulent conduct. In 2011, the Supreme Court in BP v. Marshall overruled a jury verdict in favor of royalty owners, holding that their claim was barred by limitations as a matter of law even though the jury had found that the lessee had fraudulently concealed the facts and that the plaintiffs had no reason to discover the true facts until less than two years prior to filing suit.

One justice on the Houston First Court of Appeals wrote a concurring opinion that may have influenced the Supreme Court to take the case, which bears repeating here:

It is undisputed that Samson drilled a directional well bottomed within the "buffer zone" established in the Hooks' Jefferson County Lease (the "Lease") and failed to elect between the three alternatives outlined in the Lease, thus exposing itself to liability for breach of contract. If the Lease had allowed pooling, Samson could have solved the problem by pooling the lands covered by the Lease with the adjacent lands. The Lease, however, did not allow pooling.

Samson's solution to this problem was to begin misrepresenting various "facts" to escape the consequences of its actions. Its landman, Lanoue, filed papers with the Railroad Commission falsely certifying that Samson had pooling authority from the Hooks. He later filed paperwork in the county's real property records falsely indicating that the Hooks had already agreed to pool. Lanoue then sent a letter to the Hooks asking them to agree to pool the westernmost 50 acres of the Hooks' acreage in the Lease into the BSM 1 Unit. When Charles Hooks called Lanoue and asked for more information about the well's location, Lanoue represented to Hooks that the well was located approximately 1500 feet from the lease line, a location outside the buffer zone. When Charles Hooks asked for a plat, Lanoue faxed him one that represented a bottom-hole location that was +/- 1400 feet from the lease line, the accuracy of which he, Lanoue, had certified with no reference to an actual bottom-hole location, although it was ascertainable from a prior directional survey. Instead, when asked the origin of those measurements, he answered: "I got them from myself." On this basis the Hooks agreed to the formation of the unit.

Thus it is clear that Samson, through its representative, took action to cover up its own error by both oral and written misrepresentations to its lessor, born of "assuming" and "hoping." It is further clear that the Hooks, after asking for and receiving verification of Lanoue's oral representation in the form of a plat, believed its lessee's representations and made no attempt to go beyond them to discover the truth or falsity thereof. On these facts, the majority has found that the discovery rule does not apply to the Hooks' fraud, fraudulent inducement, and statutory fraud claims and that they are barred by limitations as a matter of law.

I reluctantly concur, based on the Texas Supreme Court's holding in BP America Production Co. v. Marshall, 342 S.W.3d 59 (Tex. 2011). In that case, the Texas Supreme Court makes clear that no lies on the part of a lessee, however self-serving and egregious, are sufficient to toll limitations, as long as it is technically possible for the lessor to have discovered the lie by resort to the Railroad Commission records. This burden the Court imposes upon lessors is severe. It is now a lessor's duty to presume that any statement made by its lessee is false and to ransack the esoteric and oft-changing records at the Railroad Commission to discover the truth or falsity of its lessee's statements. If, as is often the case, these records are technical in nature and require expert review to ferret out the truth, it is the lessor's job to hire experts out of its own pocket to perform such a review. If a lessor fails to take these steps, then it will have failed in exercising reasonable diligence to protect its mineral interests and, if the lessee's fraud is successful for longer than the limitations period, the lessor's claims will be barred by limitations.

Such is the case here. Had the Hooks presumed that Samson's oral representations, followed by written representations, about the bottom-hole location of the well were false, and had they hired an expert to resort to Railroad Commission records to trace the various filings (some of which were also false), that expert could have hit upon the directional survey and, by virtue of his expertise, interpreted it to prove the falsity of the representations. Instead they merely relied on the oral and written representations of their lessee, without undergoing what doubtless seemed to them the useless expense of hiring an expert to rake through the Railroad Commission records with an eye towards exposing a potential falsehood.

I believe the Texas Supreme Court has placed an unnecessary and very heavy burden on lessors by its ruling in BP America, one that will result either in much money being spent unnecessarily on prophylactic forensic review of Railroad Commission records or in many viable claims being lost to limitations. As we are, however, bound to follow the Court's rulings, I reluctantly concur in that part of the opinion that finds the Hooks' fraud, fraudulent inducement, and statutory fraud claims barred by limitations as a matter of law.

Amicus briefs supporting Samson Lone Star were filed by the Independent Petroleum Association of America, the Texas Alliance of Energy Producers, and the Texas Oil & Gas Association. Amicus briefs supporting the Hooks' application were filed by the Texas Land & Mineral Owners' Association and by Cardwell, Hart & Bennett, a law firm that regularly represents landowners in oil and gas cases. Links to the briefs of all parties and amici can be found here. The court has not yet set a date for oral argument.

April 28, 2014

$3 Million Verdict for Nuisance in Barnett Shale Case

There's lots of buzz about a recent verdict in a case filed by a landowner in Dallas County alleging injuries from air emissions from drilling and production of Barnett Shale wells in Wise County. The case is Lisa Parr v. Aruba Petroleum, Cause No. 11-01650-E, in the County Court at Law No. 5 of Dallas County. The jury returned a verdict for personal injury and property damages of $2.9 million. According to the petition (Parr - 11th Amended Petition.pdf), Aruba had 22 wells within two miles of the Parrs' 40 acres, including one within 800 feet.

CNN quotes the plaintiff, Lisa Parr, as saying that says she's not opposed to the work oil companies do. She simply wants them to do their business responsibly.

"We are not anti-fracking or anti-drilling. My goodness, we live in Texas. Keep it in the pipes, and if you have a leak or spill, report it and be respectful to your neighbors. If you are going to put this stuff in close proximity to homes, be respectful and careful."

Here is a chart of pending cases related to hydraulic fracturing done last year by Arnold and Porter:  http://www.arnoldporter.com/resources/documents/Hydraulic%20Fracturing%20Case%20Chart.pdf 

April 1, 2014

Allocation Wells

Last Friday I spoke on a panel at the E.E. Smith Advanced Oil and Gas Institute in Houston, discussing allocation wells. The segment was in the form of a debate, actually more like an oral argument. After an introduction of the topic by Bob Goldsmith, Bryan Lauer with Scott Douglas presented the case for the legality of allocation wells, and I presented the case for their illegality. We discussed the precedential value of Browning Oil v. Luecke and Humble Oil v. West and the challenges to allocation wells in the Klotzman proceeding before the Texas Railroad Commission and in Spartan v. EOG, now pending in district court in Harris County.

I can now report that EOG and the Klotzman family have reached a settlement in the Klotzmans' challenge of an allocation well permit on their lands. So the Railroad Commission's authority to issue the Klotzman allocation well permit will not be decided by a District Court in Travis County.

Here is a recent article in the Texas Tech Law Review about allocation wells.

 

March 17, 2014

EOG Sued For Drilling Allocation Wells

I recently have learned of a suit brought by landowners against EOG Resources involving "allocation wells," of which I have written before. The case is Spartan Texas Six Capital Partners, Ltd., Spartan Texas Six-Celina, Ltd., and Dion Menser v. EOG Resources, Inc., Cause No. 2011-27476, in the 11th Judicial District Court of Harris County.  Although the case is in Harris County, it involves wells drilled by EOG in Montague County. The EOG wells are shown on the sketch below; the plaintiffs' tract is in yellow:

 

Spartan v. EOG.JPG

EOG filed pooled unit designations for the Knox, Howard, Howard A, and Wylie A units, even though the plaintiffs' leases did not allow pooling. EOG then calculated the plaintiffs' royalties based on the portion of each well's lateral length located on plaintiffs' tract - allocation based on lateral length. I understand that most companies drilling allocation wells calculate royalties owed on non-pooled tracts on this lateral-length yardstick.

I have reviewed some of the pleadings in the Spartan case, including a motion for partial summary judgment filed by EOG last month. EOG asks the court to rule that "royalties in this case should be based on a reasonable allocation of the total production attributable to the lands covered by the [plaintiffs'] leases," citing Browning Oil Company, Inc. v. Luecke, 38 S.W.3d 625 (Tex.App.-Austin 2000, pet. denied).

Plaintiffs contend that they should be paid royalties based on 100% of production from the wells. Their theory is that, by producing the wells, EOG has commingled production from their land with production from other tracts. Plaintiffs rely on Humble Oil & Ref. Co. v. West, 508 S.W.2d 812, 818 (Tex. 1974), where the Texas Supreme Court said:

[T]he burden is on the one commingling the goods to properly identify the aliquot share of each owner; thus, if goods are so confused as to render the mixture incapable of proper division according to the pre-existing rights of the parties, the loss must fall on the one who occasioned the mixture. ... Stated differently, since Humble is responsible for, and is possessed with peculiar knowledge of the gas injection, it is under the burden of establishing the aliquot shares with reasonable certainty.

Plaintiffs say that it is impossible for EOG to determine "with reasonable certainty" how much of the wells' production is from their tract. EOG argues that Browning v. Luecke supports its use of lateral-length allocation. 

If this case makes it to the appellate courts, it will (as far as I am aware) be the first case since Browning v. Luecke to address what remedies lessors have when their lessee drills a horizontal well across their lease boundary without forming a pooled unit. According to deposition testimony in the Spartan case, these are the first allocation wells actually drilled by EOG, although it has filed allocation well permits before. In fact, the permits for the wells drilled on the Spartan tracts were not filed as allocation well permits.

As in the Klotzman RRC proceeding now on appeal (in which our firm represents the lessors), EOG contends that the drilling of the wells across the Spartan lease did not violate the lease. It does not argue that, by allocating production between the tracts crossed by the wells, it has pooled the tracts. Its view is that the only issue to be resolved is whether its use of the lateral-length allocation method satisfies its obligation to determine what portion of the wells' production comes from the Spartan lease "with reasonable certainty."

March 11, 2014

Chesapeake v. Hyder - Royalty Owner Wins Gas Royalty Dispute

Last week, the Fourth Court of Appeals in San Antonio issued its opinion in Chesapeake v. Hyder.pdf, on gas royalties owed to the Hyder family for production in Johnson and Tarrant Counties, in the Barnett Shale. The court upheld a judgment against Chesapeake for more than a million dollars, including $250,000 in attorneys' fees. The result is not surprising considering the language in the lease, but the case is interesting because it reveals Chesapeake's structure for marketing of gas in the Barnett Shale, obviously designed to reduce its gas royalty obligations.

The principal issue on appeal was whether Chesapeake could reduce the Hyders' royalty by the amount of transportation costs paid by Chesapeake to unrelated pipeline companies. The trial court and court of appeals held that it could not. As I have written before (here, here and here), deductibility of post-production costs is a continuing issue for gas royalty payments in Texas. Prior Supreme Court cases have held that such costs are deductible under most standard gas royalty clauses.

The Hyders' royalty clause was not a standard lessee-form lease. It provided:

Lessee covenants and agrees to pay Lessor the following royalty: ... (b) for natural gas, including casinghead gas and other gaseous substances produced from the Leased Premises and sold or used on or off the Leased Premises, twenty-five percent (25%) of the price actually received by Lessee for such gas. Lessee shall not sell hydrocarbons to entities owned in whole or in part by Lessee or to entities affiliated with Lessee in any way, without the express written consent of Lessors. The royalty reserved herein by Lessors shall be free and clear of all production and post-production costs and expenses, including but not limited to, production, gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing, delivering, or any other costs and expenses incurred between the wellhead and Lessee's point of delivery or sale of such share to a third party. ... In no event shall the volume of gas used to calculate Lessors' royalty be reduced for gas used by Lessee as fuel for lease operations or for compression or dehydration of gas. ... Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provision of this Lease.

Chesapeake has different affiliated companies, each of which has a different role in the process of production, gathering, marketing and sale of its gas. The owner of the lease is Chesapeake Exploration, LLC. Chesapeake Operating, Inc., drills and operates the wells and pays the royalty. Chesapeake Energy Marketing, Inc., buys the gas from Chesapeake Operating (as agent for Chesapeake Exploration). Chesapeake Midstream Partners, LP gathers the gas from the leases and delivers it to pipelines owned and operated by unrelated parties. Those pipelines in turn deliver the gas to purchasers, who pay Chesapeake Energy Marketing, Inc. Confused yet? It gets better.

Chesapeake's royalties are based on a weighted-average sales price for all gas that passes through the gathering system and sold to third parties: total proceeds received divided by total gas sold equals the weighted average sales price, or "WASP". The contract between Chesapeake Operating and Chesapeake Energy Marketing provides that the price paid to Chesapeake Operating is the price received by Marketing for the sale of the gas to third parties, less all costs incurred by Marketing to get the gas to the ultimate purchaser - both the gathering costs charged by Chesapeake Midstream Partners and the pipeline fees charged to transport the gas to the ultimate buyer - plus a "marketing fee" of 3% paid to Marketing. For most royalty owners, Chesapeake pays royalty on this net price, after deducting all post-production costs, including the gathering fees charged by Midstream Partners and the marketing fee charged by Marketing.

But the Hyders' lease prohibited Chesapeake from selling gas to an affiliate without the Hyders' consent, which it never obtained. So Chesapeake agreed that its royalty should be based on its weighted average sales price, without deduction of fees charged by Marketing or Midstream Partners. But Chesapeake claimed that it could deduct the pipeline transportation costs charged by unaffiliated pipelines to transport the gas to the ultimate buyer. This issue became the principal dispute in the case. The trial court and court of appeals agreed that such costs could not be deducted. "Free and clear of all costs" means just what it says, said the courts.

Another interesting issue in the case was whether Chesapeake must pay royalty on gas "lost and unaccounted for." The facts showed that not all gas produced from the Hyder lease was sold:

- some gas was used by Chesapeake as "gas lift" gas, -- that is, reinjected down the wellbore to assist in production from the well.

- some gas was used as fuel for compression and dehydration of gas produced from the lease - "lease-use gas."

- some gas was lost and unaccounted for between the wellhead and the point of delivery to the ultimate purchaser. This gas is lost through leaks in the gathering and transportation system.

Chesapeake agreed that the lease required it to pay royalty on all gas "produced and sold or used ...." It agreed that gas used as fuel for compression and dehydration was gas "used". But Chesapeake argued that it did not have to pay royalty on gas lost and unaccounted for. That gas was neither sold nor used. On this point, the trial court and court of appeals agreed with Chesapeake. "Gas lost or unaccounted for is neither sold nor used." (The parties agreed that no royalty was owed on gas-lift gas.)

The Hyder lease also had a special provision allowing the lessee to locate wells on the leased premises drilled horizontally onto adjacent lands. For such well locations, the lessee agreed to pay to the Hyders a "cost-free" overriding royalty. Chesapeake claimed that it could deduct post-production costs in calculating the Hyders' overriding royalty. The trial court and the court of appeals disagreed; "cost-free" means free of all costs, including post-production costs.

One of the remarkable things about this case is that Chesapeake argued in the trial and on appeal that it should not have to pay royalty on gas lost and unaccounted for because the only "price received" by Chesapeake was the price paid for the sale of the gas to non-affiliated third parties. In fact, Chesapeake obtained a finding from the trial court to that effect. Chesapeake's attorneys showed that the first "buyer" of the gas, Chesapeake Energy Marketing, never received any money from the sale of the gas and never paid any money to Chesapeake Operating, the seller, or Chesapeake Exploration, the owner, even though the gas sales contract for the "first sale" of the gas was between Chesapeake Operating and Chesapeake Energy Marketing. It appears to me that Chesapeake was in effect admitting that its marketing arrangement with its affiliate Chesapeake Marketing was a sham.

Another interesting fact revealed in the Hyders' briefs is that, between 2005 and 2011, Chesapeake changed the way it calculated the Hyders' royalty four times. Initially, it calculated the Hyders' royalty based on the total wellhead volume, using the WASP. Then it began paying only on the volumes sold to unrelated third parties, less third-party transportation costs. Then it stopped deducting transportation costs and paid based on the well-head volume times the WASP. Then it began paying on the volumes sold to third parties, less third-party transportation charges.

It is my experience that Chesapeake does not show any post-production-cost deductions on its check details and refuses to provide that information to royalty owners unless the royalty owner is granted the right to audit its royalties in his/her oil and gas lease--and even then it sometimes refuses. Trying to determine whether a royalty owner is being unlawfully charged post-production costs is very difficult. Trying to collect those charges, even with very good lease language like the Hyders', is expensive and time-consuming, as the Hyders have learned.

February 12, 2014

Julia Crawford Continues Fight Against Keystone XL Pipeline

Julia Trigg-Crawford, a landowner in Lamar County, has asked the Texas Supreme Court to hear her case arguing that TransCanada has no right to condemn her property for the Keystone XL Pipeline.  The Crawford Family Farm Partnership v. TransCanada Keystone Pipeline, L.P., No. 13-0866. Although other segments of the pipeline await federal approval, the segment from Oklahoma across Texas has now been completed and is in operation.  Crawford lost her case in the trial court and the Texarkana Court of Appeals, 409 S.W.3d 908, and has asked the Supreme Court to review the case. The Supreme Court asked TransCanada to reply to Crawford's petition, and Texarkana filed its reply on February 6. 

Crawford's argument is that Texas law does not grant eminent domain powers to interstate pipelines.  TransCanada argues that Crawford's appeal presents the same issues as Rhinoceros Ventures Group, Inc. v. TransCanada Keystone Pipeline, L.P., 388 S.W.3d 305 (Tex. App.--Beaumont 2012, pet. denied), which the Supreme Court declined to review.

Crawford has become a symbol of opposition to the Keystone pipeline, drawing national attention to her cause.

January 16, 2014

Klotzmans Appeal RRC EOG Allocation Well Ruling

The Klotzman mineral owners have appealed the Texas Railroad Commission's order granting EOG a permit to drill an "allocation well" on their land. A copy of the petition can be viewed here: Klotzman Petition.pdf. Our firm represents the Klotzmans.  For my previous posts about allocation wells and the Klotzman case, search for "allocation well" in the site's search engine.
January 13, 2014

Springer Ranch, Ltd. v. Jones - Interesting Case on Horizontal Wells

The San Antonio Court of Appeals recently decided a case illustrating the new kinds of issues that can arise from the drilling of horizontal wells.

In Springer Ranch v. Jones, Alice Burkholder owned a ranch, 8,545 acres in La Salle and Webb Counties. She signed a single oil and gas lease on the ranch in 1956 that has been maintained by produciton. When she died, Alice left the ranch to her husband for life, and thereafter in three separate tracts to her three children.  In effect, by her will she partitioned the ranch, surface and minerals, into three tracts, subject to the oil and gas lease.  Alice's husband died in 1990, and thereafter the three children signed a contract agreeing on how royalties on production from the lease should be divided among them. The contract provided that all royalties under the lease "shall be paid to the owner of the surface estate on which such well or wells are situated, without reference to any production unit on which such well or wells are located."

The lessee drilled a horizontal well located partly on one of the ranch tracts, now owned by Springer Ranch, and partly under a different tract now owned by Rosalie Sullivan. The surface location of the well was on the Springer Ranch tract.  Springer Ranch argued that, because the surface location was "situated on" its property, it should receive all royalties from the well. Rosalie Sullivan argued that royalties from the well should be allocated between the two tracts based on each tract's part of the productive lateral of the well.  The trial court agreed with Ms. Sullivan, and the court of appeals affirmed. It construed the parties' agreement to to allocate royalties on the basis of the percentage of the productive interval of the wellbore on each party's tract, not on the basis of the well's surface location.

Springer Ranch challenged the formula adopted by the trial court for allocating production between the two tracts.  That formula was proposed by Ms. Sullivan's expert, who measured the total length of the wellbore from its first to last take point and the portion of that length on each tract. Springer Ranch argued that the formula should be based on the entire length of the wellbore on each tract, and not just the productive portions. The court of appeals disagreed. It noted that Springer Ranch did not offer any evidence of any other basis for determining how much production was obtained from the parts of the well on each tract, and that the testimony supporting Ms. Sullivan's allocation method was sufficient evidence to support the trial court's judgment.

This kind of situation often arises where a portion of a tract subject to a lease is burdened by a non-participating royalty interest.  If a well drilled on the lease is partly located on the tract burdened by the NPRI, there must be some method of allocating production to the NPRI tract for purposes of paying royalties.  Most operators use the method adopted by the court in the Springer Ranch case, although I have seen no case law approving such a method.  Note that the Springer Ranch case is based on the parties' express agreement as to how production should be allocated.  In most cases, there will be no express agreement.

It should also be noted that the Springer Ranch case has nothing to do with the "allocation well" controversy, which arises when an operator drills a horizontal well crossing from one lease to another without pooling the two leases together. In Springer Ranch, there was no dispute that the lessee had the right to drill the well.

December 30, 2013

Another Chapter in EPA's Battle with Range Resources in Parker County

On December 20, the Office of Inspector General of the Environmental Protection Agency issued its "Response to Congressional Inquiry Regarding the EPA's Emergency Order to the Range Resources Gas Drilling Company."  The report was requested by Congress as a result of an emergency order issued by the Dallas regional office of the EPA against Range Resources on December 7, 2010. That order required Range to take certain actions based on EPA's finding that Range's wells in the Barnett Shale were the likely source of contamination of water wells in Parker County.

I have written about Range's saga before.  EPA sued Range to enforce its emergency order. Range disputed and fought the EPA order, suing in the U.S. Court of Appeals to get the order revoked. Range called a hearing before the Texas Railroad Commission (in which EPA did not participate), after which the RRC found that Range's wells were not the source of the gas in the water wells. One of the well owners, the Lipskys, sued Range in state court for damages;  Range countersued, contending that the Lipskys had falsified evidence and defamed the company. The district court found that Lipsky had created a "deceptive video" that was "calculated to alarm the public into believing the water was burning." The Lispkys have appealed to the Texas Supreme Court, where their case remainds pending.


Read more here: http://www.star-telegram.com/2012/02/17/3744111/owner-of-contaminated-water-well.html#storylink=cpy

The EPA and Range eventually settled their dispute, Range agreeing to conduct tests of 20 water wells in the area every 3 months for a year. Those tests showed no methane contamination of the water wells.

The Range-EPA fight led to the resignation of the Dallas regional admnistrator of the EPA, Dr. Al Armendariz, after he was videoed saying that, because of the limited number of staff in his office, his enforcment approach is to act like the Romans: "They'd go into a little Turkish town somewhere, they'd find the first five guys they saw and they would crucify them. And then you know that town was really easy to manage for the next few years."  His actions were criticized in Congress, leading to a congressional request that the Office of Inspector General investigate EPA's actions in the Range matter.

The OIG's report vindicates EPA's actions.  If found that the EPA's actions "conformed to agency guidlines, regulations and policy." It also found that "the EPA lacks quality assurance information for the Range Resources' sampling program, and questions remain about the contamination."

A large part of the controversy concerned the EPA's "isotopic fingerprinting and compositional analysis" of the gas in the Lipskys' well, from which EPA concluded that the methane came from the Barnett Shale.  In Parker County, the principal aquifer lies just above a shallow formation that contains methane, and water wells will become contaminated with that methane if they are drilled through the aquifer into the shallow gas sands. Range's evidence at the RRC hearing showed that EPA's "isotopic" analysis was flawed and that the gas in the Lipskys' well was not from the Barnett Shale. Range's evidence for the source of the gas is not mentioned in the OIG report.

Armendariz, now employed by Sierra Club, said that the OIG report is "complete and total vindication of the work we did at EPA."  Lipsky continues to believe that Range is responsible for contamination of his well:  "The holding tanks [for well water] in people's garages are going to explode and I don't care where it's coming from, someone is going to get killed," he said.

December 9, 2013

"Induced Seismicity" Caused By Wastewater Injection in Barnett Shale

StateImpact Texas has published a series of good articles about the growing evidence that the huge quantities of wastewater being injected in the Barnett Shale field are causing earthquakes -- some of sufficient intensity to cause significant damages. Lawsuits have been filed in Johnson County to recover for the damage.  StateImpact's most recent article can be found here. Links to all of StateImpact's articles on earthquakes caused by oil and gas activity are here.
December 6, 2013

FPL Farming Case - Can Salt Water Injection Wells Cause Subsurface Trespass?

   Suppose that the fluids injected into a disposal well migrate beyond the boundary of the tract where the well is located; does that incursion of the injected fluids into and under the neighbor's property constitute a trespass?  Until recently, this question had never been addressed by a Texas appellate court, and the assumption in the disposal industry was that such incursion was not actionable. The Beaumont Court of Appeals, in FPL Farming Ltd. ("FPL") v. Environmental Processing Systems, L.C. ("EPS"), concluded that the neighbor does have a trespass claim. 

  The Beaumont Court of Appeals has issued two opinions in the case; the first was appealed to the Supreme Court which reversed and remanded to the Court of Appeals, and the second has also been appealed to the Supreme Court, where it is now pending. FPL Farming Ltd. v. Environmental Processing Systems, L.C., 305 S.W.3d 739 (Tex.App.-Beaumont), reversed and remanded 351 S.W.3d 306 (Tex. 2011), on remand 383 S.W.3d 274 (Tex.App.-Beaumont May 24, 2012, pet. filed 1/18/13).  

  The facts in FPL are these:  EPS operates an injection well for non-hazardous waste on land adjacent to the land owned by FPL. FPL previously objected to an amendment of EPS's permit that increased the rate and volumes allowed to be injected. The Austin Court of Appeals affirmed the permit amendment over FPL's objections, ruling that "the amended permits do not impair FPL's existing or intended use of the deep subsurface." FPL Farming Ltd. v. Tex. Natural Res. Conservation Comm'n, 2003 WL 247183 (Austin 2003, pet. denied).

   FPL then sued EPS for trespass and negligence, alleging that injected substances had migrated under FPL's tract causing damage. FPL lost a jury trial and appealed. The Beaumont Court affirmed, holding that because EPS held a valid permit for its well, "no trespass occurs when fluids that were injected at deep levels are then alleged to have later migrated at those deep levels into the deep subsurface of nearby tracts." FPL Farming Ltd. v. Environmental Processing Systems, L.C., 305 S.W.3d 739, 744-745 (Tex.App.-Beaumont). The Supreme Court reversed, holding that Texas laws governing injection well permits "do not shield permit holders from civil tort liability that may result from actions governed by the permit." FPL Farming Ltd. v. Environmental Processing Systems, L.C., 351 S.W.3d 306, 314 (Tex. 2011). But the court was careful to say it was not deciding that owners of injection wells could be guilty of trespass if their injected fluids migrated onto other lands. "We do not decide today whether subsurface wastewater migration can constitute a trespass, or whether it did so in this case." Id.  The court remanded to the court of appeals for it to consider the other issues raised by the appeal.

  In its second opinion, the Beaumont court held that FPL did have a cause of action for trespass: "[T]he Texas Supreme Court has, by implication, recognized that the law of trespass applies to invasions occurring on adjacent property but at a level beneath the surface."  Testimony was presented that the waste plume affected the briny water in place under FPL's property, "even though it was not presently using the briny water." The court said that the briny water belongs to the surface owner, and that EPS's permits did not give EPS an ownership interest in the formations below FPL's property. The Beaumont court reversed and remanded the case for a new trial, holding that the trial court's jury instruction erroneously put the burden on the landowner to prove that he had not consented to the injection under his property. Additionally, the court noted that the fact that EPS is using the deep subsurface for commercial purposes indicates that the subsurface levels at issue have economic potential for storing waste, which otherwise, absent its safe storage, has the potential to adversely affect the environment. Thus, without a trespass remedy, a party--in this case, FPL--does not have all of the legal remedies typically available to owners to protect the owner's right to the exclusive use of its property.

  EPS also claimed that its trespass onto FPL's property did no actual harm. The court said that EPS had failed to show as a matter of law that no injury had occurred, and that FPL was entitled to a jury trial on that issue.

   So the Beaumont court of appeals' opinion, if it stands, recognizes a trespass claim for subsurface migration of injected fluids.  The fear for the industry is not necessarily a suit for damages, which may be too difficult to prove.  If subsurface trespass is found to be a viable claim, potential plaintiffs could seek an injunction to stop a well from injecting fluids underground.

  The Texas Supreme Court has set the case for oral argument at 9 am on January 7. You can view the oral argument online.

November 25, 2013

Chesapeake and Post-Production Costs

Lawsuits against Chesapeake Exploration for wrongfully deducting post-production costs from its gas royalty payments are hitting a boiling-point. Suits are being pursued against the company in every jurisdiction where it operates, including Texas, Arkansas, Lousiana, Kansas, Ohio, West Virginia, Oklahoma and Pennsylvania. Chesapeake has recently been much more aggressive in deducting post-production costs. In the Barnett Shale in North Texas, its post-production cost deductions have been as much as $.70 to $1.00 per mcf, and with such low gas prices, some royalty owners' payments have been halved by such deductions. Chesapeake's royalty payments in North Texas have reportedly been on a net price of as little as eleven cents per mcf, and as little as 11% of the price other producers have based their royalty payments on. A recent Bloomberg article summarizes Chesapeake's royalty payment practices.

Chesapeake has settled some claims, including large royalty owner claims in Pennsylvania. Chesapeake's marketing practices in Pennsylvania mirror those it uses in the Barnett Shale.  Last year, Chesapeake settled a claim brought by the Dallas-Fort Worth Airport for underpayment of royalties for $5 million. The Bass family in Fort Worth recently sued the company for wrongfully deducting post-production costs.

Chesapeake's tactics for how it calculates its royalties cannot be understood without knowing something about how Texas courts have addressed deductibility of post-production costs. I have previously written three posts on this topic that can be seen here, here and here.

Oil company oil and gas lease forms historically have provided that royalties on natural gas are based on "market value at the well" or the "net amount realized at the well." Texas courts have construed such leases to allow the producer to deduct from gas sale proceeds the costs of gathering, transporting, treating and processing gas after it has been produced but prior to sale. In response, mineral owners in Texas began adding "no-deduction" clauses to their leases, prohibiting deduction of such costs for purposes of calculating their royalty.  One such clause from a famous Texas Supreme Court case, Heritage Resources v. Nationsbank, 939 S.W.2d 118 (Tex. 1996), said: "provided, however, that there shall be no deductions from the value of the Lessor's royalty by reason of any required processing, cost of dehydration, compression, transportation or other matter to market such gas."  To most oil and gas attorneys' suprise, the Supreme Court in Heritage v. Nationsbank held that, despite this no-deduction clause, Heritage Resources was entitled to deduct transportation costs from Nationsbank's royalty. The court reasoned that, because the lease provided that royalty would be based on the "market value at the well" of the gas, no deductions were being made from that value in calcluating Nationsbank's royalty. The Supreme Court deemed the no-deduction language to be "surplusage."

Since Heritage v. Nationsbank, landowners have begun to include language in their leases expressly stating that their lease should not be construed like the lease in Heritage. But despite such efforts, Chesapeake has relied on the Heritage case to continue deducting post-production costs from its royalty payments.

Two Texas cases challenging Chesapeake's right to deduct post-production costs are now on appeal to the U.S. Court of Appeals for the Fifth Circuit, both appealed from the U.S. District Court in Dallas:  Potts v. Chesapeake, Case No. 13-1061, appealed from the U.S. District Court in Dallas; and Warren v. Chesapeake, District Court No. 3:12-cv-03581-M. In both cases, Chesapeake won in the trial court and the royalty owners are appealing.

The cases reveal that, in the Barnett Shale, Chesapeake sells its gas to its wholly-owned subsidiary, Chesapeake Energy Marketing Inc. (CEMI). The sales contract provides that CEMI takes custody of the gas at the wellhead.  CEMI then gathers the gas and sells it to various purchasers at various prices. The Chesapeake-CEMI contract provides that the price paid to Chesapeake for the gas will be the weighted-average sales price of all gas sold by CEMI from Chesapeake wells in the area, less post-production costs incurred by CEMI. By structuring its sales through its affiliate and providing for the contract point of delivery to be at the wellhead, Chesapeake seeks to take advantage of its leases that provide for royalties based on "market value at the well," as construed by Heritage v. Nationsbank.

The oil and gas lease construed in Warren v. Chesapeake appears to fall squarely within the Heritage holding: it provides for royalty based on "the amount realized by Lessee, computed at the mouth of the well." A provision added by the landowner states:

Notwithstanding anything to the contrary herein contained, all royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation. Lessor will, however, bear a proportionate part of all those expenses imposed upon Lessee by its gas sale contract to the extent incurred subsequent to those that are obligations of Lessee.

The lease construed in Potts v. Chesapeake is much more interesting, and presents a closer case. Its language is contained in two paragraphs. The first provides that royalty shall be based on the "market value at the point of sale," and that "all royalty paid to [Lessors] shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas produced from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation." A separate paragraph provides that "Payments of royalties to Lessor shall be made monthly and shall be based on sales of leased substances to unrelated third parties at prices arrived at through arms length negotiations."

The plaintiff in Potts argues that his lease is not controlled by Heritage v. Nationsbank; his royalties are to be based on the price "at the point of sale," not "at the well"; and his royalties must be based on the sale price to unrelated parties arrived at in arms-length negotiations, not the price in the Chesapeake contract with its affiliate CEMI.

Chesapeake argues that it has complied with both lease provisions. First, since it sells its gas at the well, the "market value at the point of sale" is the same as the "market value at the well," so it is in compliance with the first lease provision in paying based on the price it receives from CEMI.  Second, because the price CEMI pays Chesapeake for the gas is based on the weighted-average price for CEMI's sales of gas to unrelated parties in arms-length transactions, it is complying with the second lease provision.

It seems clear that the landowner in Potts was attempting to draft his lease to prevent deduction of post-production costs and to require that his royalties be based on the price received in the first arms-length sale of his gas.  Whether he accomplished that intent is a matter for the Fifth Circuit Court to decide.