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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.

 

October 25, 2013

Klotzman Allocation Well Proceeding

For those following the Klotzman allocation well dispute, here are links to the replies of EOG and intervenors to the Klotzmans' motion for rehearing at the Railroad Commission:

2013-10-24_Reply to Motion for Rehearing docx.pdf

2013-10-24 Intervenors Reply to Mtn Rehrg-filed.pdf

September 10, 2013

RRC Rules Aginst Klotzman in EOG Allocation Well Permit Case

The Texas Railroad Commissioners voted unanimously today to reject the recommendation of its examiners denying EOG's allocation well permit and instructed the examiners to prepare an order and findings granting EOG's permit.  For my prior posts about this case, see here, here and here.

September 3, 2013

Julia Crawford Loses Appeal of her XL Keystone Pipeline Fight, Vows to Fight On

Julia Trigg Crawford has waged a well-publicized fight to prevent condemnation of an easement across her farm for the XL Keystone Pipeline.  On August 27, the 6th Court of Appeals in Texarkana denied her appeal of TransCanada Keystone Pipeline's award of an easement over her property.  Crawford has vowed to appeal to the Texas Supreme Court.

The Court of Appeals' opinion says that Ms. Crawford had two arguments: first, that the Texas statutes granting pipelines condemnation authority do not apply to interstate pipelines; and second, that Keystone had failed to meet the showing required by the Texas Supreme Court in Texas Riceland Partners v. Denbury Green Pipeline-Texas, 363 S.W.3d 192, 202 (Tex. 2012) that the pipeline must show "a reasonable probability ... that the pipeline will at some point after construction serve the public by transporting gas for one or more customers who will either retain ownership of their gas or sell it to parties other than the carrier." The Texarkana court held that Keystone had met that burden. The court also held that the relevant Texas statutes do grant condemnation authority to interstate common carrier pipelines.

The portion of the XL Keystone pipeline from Cushing, Oklahoma to Port Arthur, Texas is nearing completion.  That segment of the pipeline has been able to proceed even though the Obama administration has not yet approved the segment of the system that would carry heavy crude from Canada across the northern segment of the XL Pipeline system.

The Supreme Court's Denbury opinion initially caused significant consternation in the pipeline industry and generated unsuccessful efforts in the last Texas legislative session to amend Texas condemnation statutes to facilitate pipeline condemnations.  The Crawford case is an indication that the industry's fears that Denbury would significantly impair pipeline construction in Texas are unfounded and that Texas appellate courts have been able to apply Denbury without much trouble.

July 30, 2013

Klotzman Protest of EOG "Allocation Well" Permit

For those following this case, our reply to the parties' exceptions to the proposal for decision can be viewed here.  Protestants Replies to Exceptions to the PFD and Mtn to Strike.PDF
July 23, 2013

Allocation Wells - A Nerve Has Been Struck

For those following the Klotzman protest of EOG's allocation well permit (our firm represents the protestants), here are the exceptions to the examiners' proposal for decision filed by EOG and by Intervenors Devon, Pioneer, Laredo Petroleum and BP America:

EOG Exceptions to PFD.pdf

Devon et al Exceptions to PFD.pdf

Here is a link to the proposal for decision:

2013-06-25 PFD EOG Klotzman (2).pdf

EOG has called on other operators and industry organizations to file objections to the PFD, and they have responded. Letters opposing the PFD have been filed by Diamondback Energy, Halcon Resources, EP Energy, Oxy, Crimson, XTO, Burlington, Texas OIl and Gas Association, Texas Independent Producers and Royalty Owners Association, Texas Alliance of Energy Producers, Panhandle Producers and Royalty Owners Association, and Permian Basin Petroleum Association. Clearly, this PFD has hit a nerve. A typical letter, from Marathon, claims that the PFD would "prevent the drilling of countless horizontal wells throughout the State and cause tremendous, otherwise producible, reserves to be wasted and left in the ground." The sky is falling.

Operators say that more than 100 allocation well permits have been granted to some 17 operators across the State.  According to the PFD, between April 27, 2010 and the date of the Klotzman hearing on December 3, 2012, 55 permits were approved for "allocation" wells.  During that same time period, the Commission granted 18,335 permits for horizontal wells. So for that time period, allocation well permits were three tenths of 1 percent of all permits granted. More than 4,000 permits were issued by the Commission for Eagle Ford wells alone in 2012, and some 2,000 Eagle Ford permits have been issued this year. The Commission issued a total of 22,479 drilling permits in 2012. Based on these figures, it hardly seems possible that the Commission's decision not to issue allocation well permits would cause "tremendous reserves" to be wasted.