I recently ran across this very good article on the tax treatment of payments received for granting of pipeline easements:
National Geographic has started a website called The Great Energy Challenge that provides a wealth of information about energy and the environment. “The Great Energy Challenge convenes and engages influential citizens and key energy stakeholders in solutions-based thinking and dialogue about our shared energy future.” Multiple articles from distinguished scientists provide education, explore innovative technologies, and seek to engage the public in a meaningful way about our energy future. Its home page is here.
Here is a good article discussing five innovative technologies for cleaner shale energy production and transportation, including water-free fracing, using recycled water or brackish water for fracing, using natural gas instead of diesel fuel to power drilling and completion, and efforts to reduce methane emissions in exploration, production and transportation of natural gas.
Here is a quiz to see how much you know about water and energy. Did you know that it takes 2.8 to 6.6 gallons of water to refine one gallon of gasoline? That it takes 780 gallons of water to produce one gallon or corn ethanol?
Here is a good interactive graphic showing how a horizontal well is drilled and completed.
Here are blog posts by National Geographic’s panel of experts.
Lots of good information and discussion about global energy issues.
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:
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.”
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.
Ceres, a nonprofit focusing on climate change, water scarcity and sustainability, has issued a report, Hydraulic Fracturing & Water Stress: Water Demand by the Numbers, a Shareholder, Lender & Operator Guide to Water Sourcing. Here are some excerpts:
As drilling activity in the onshore US continues to grow, more and more attention is being paid to the environmental effects of exploration and production. Media stories abound about groundwater contamination, the demand for fresh water from hydraulic fracturing, increased air emissions from exploration and production, controversy over pipeline condemnation and construction, earthquakes linked to wastewater injection, increased traffic and accidents, and effects on endangered species. Recent examples:
This week The Center for Public Integrity, InsideClimate News and The Weather Channel released a report, Big Oil, Bad Air, on the effects of drilling in the Eagle Ford Shale on air quality in South Texas. The report is highly critical of the lack of regulation by the Texas Commission of Environmental Quality (TCEQ) of emissions from oil and gas exploration and production operations in that region. Criticism of the report has already hit the media. Here is an industry response to the report from Energy in Depth, a website sponsored by industry. The TCEQ says it plans to conduct video surveillance of air quality over the region this summer.
Last month, the TCEQ and the US Environmental Protection Agency settled their dispute over EPA’s requirements for reducing emissions from industry in Texas. EPA had revoked TCEQ’s air permitting authority for failing to follow EPA requirements. As a result, permitting was greatly delayed for new projects, causing industry to pressure TCEQ and the State to settle the dispute so that permitting authority could be restored to TCEQ. Texas has been in a continuing series of battles with the EPA, and has sued the agency 18 times in the last 10 years. Gubernatorial candidate Greg Abbott has touted his battles with the EPA in his campaign. (“As Texas has proven in other lawsuits against the EPA, this is a runaway federal agency that must be reined in.”)
Debate continues over whether increased production and use of natural gas reduces greenhouse gas emissions. A large part of that debate is centered around how much methane is leaked in the process of producing and transporting it to end users.
With the ongoing drought, the exploration industry’s water use in fracing has come under increased scrutiny. The EPA is engaged in a long-term study of the effect of industry activity on groundwater resources.
In Pennsylvania, drillers must submit a water-use plan disclosing how much water will be used, where it comes from, and what effect it will have on local sources; and the plan must include water recycling. In Texas, the exploration industry’s use of groundwater is largely exempt from regulation by local groundwater districts and is placing a strain on groundwater resources in South and West Texas. There is no effort yet in Texas to require companies to recycle. The first sustained use of water recycling on a big scale has been implemented by Apache in the Permian Basin, where Apache has installed a central water recycling system. To date, water recycling is still more expensive than using groundwater in most plays. But in the Permian, where groundwater is scarce, landowners have been selling their water for as much as a dollar a barrell, making recycling more competitive.
Earthquakes linked to oil and gas activity continue to make the news. In Texas, the town of Azle has made news protesting before the Texas Railroad Commission about quakes in the Barnett Shale they say are caused by injection wells. RRC candidates have expressed skepticism about any link between the quakes and oil and gas activity. The RRC has hired a seismologist and is studying the matter, but so far has not shut down any injection wells in the area. Increased seismic activity in Oklahoma has been linked to industry injection wells there. In Arkansas, companies have shut down two injection wells believed to be linked to more than 1,000 unexplained earthquakes in the region.
In the later chapters of The Quest, Daniel Yergin summarizes the history of the internal combustion engine. He begins by recounting a meeting of Henry Ford and Thomas Edison at a convention in August 1896, at which they sat together. Ford had just built his first gasoline-powered “quadricycle.” He sketched out his design to Edison. Edison told him that the problem with electric-powered vehicles is that they “must keep near a power station.” Edison told Ford to stick with the internal combustion engine.
The internal combustion engine was invented by Nikolaus Otto. His “Otto cycle” engine, developed in 1876, is still recognizable in our engines today: valves, a crankshaft, spark plugs, and a single cylinder. Otto teamed with Karl Benz to produce automobiles, and Gottlieb Daimler was in close competition. (In the twentieth century, the two companies merged, though Benz and Daimler never met each other.) By the 1890’s Daimler was distributing his cars in America.
Germany competed with France — with the French engineers Armand Peugeot and Louis Renault — for supremacy in the development of the automobile. Britain was initially left behind because its railway industry, fearing competition, got Parliament to pass the Red Flag Acts that limited “road locomotives” to four miles an hour in the country and two miles an hour in cities — as well as requiring a man carrying a red flag to walk in front of road vehicles hauling multiple wagons.
At the turn of the last century, the internal combustion engine was well behind other technologies, including steam and electricity, in the auto industry. In 1900, most of the 2,370 cars in New Yor City, Boston and Chicago were either seam cars like the Stanley Steamer or electrics. But electrics faced the problem of battery life — just as they do today. Edison worked on improving batteries, but in 1908 Ford introduced his first Motel T, priced at only $825. A few years later Ford introduced the assembly line, and the rest, as they say, is history. By 1910, the race between electric and gasoline was over.
The automobile also saved the oil industry. Until Americans fell in love with their car, gasoline was mostly a byproduct of the refining process, which produced kerosene for lighting. Just when electricity was spelling the end of the kerosene lamp, the automobile saved the day, opening a new market for the oil industry. The first gas staion, or “station for autoists,” opend in St. Louis in 1907. By the end of the 1920’s, there were hundres of thousands of gas stations. Americans were hitting the roads.
The internal combustion engine has dominated the transportation industry because, as Yergin says, “it turned out that gasoline was a very effective energy packet when poured into an internal combustion engine.” Ten gallons of the stuff could carry 2,000 pounds 100 or even 200 miles.
To understand the power of gasoline, a little basic chemistry is necessary. (A very little – as a lawyer, I’m skating close to the edge here.)
Gasoline is composed of different mixtures of hydrocarbons. Hydrocarbons are molecules that contain carbon and hydrogen atoms. The simplist hydrocarbon molecule is methane (the natural gas you burn in your stove), which contains one carbon and four hydrogen molecules – CH4. Ethane, also a gas, contains two carbon atoms and six hydrogen atoms – C2H6. Propane contains three carbon atoms and eight hydrogen atoms– C3H8. Butane contains four carbon atoms and ten hydrogen atoms – C4H10. Methane, ethane, propane and butane are all gases at atmospheric pressures. But as the hydrocarbon chain becomes longer, it is easier to compress these gases into a liquid. Butane and Propane are sold by the gallon, under pressure. Methane requires much higher pressures to condense into a liquid, making it technologically more difficult to use it as a transportation fuel.
Pentanes, hexanes, heptanes and octanes are hydrocarbons with five, six, seven and eight carbon atoms. These hydrocarbons tend to be liquid at atmospheric temperatures and pressures. They make up the components of gasoline.
When hydrocarbons ignite, the chemical reaction produces carbon dioxide, water, and energy. The formula for combustion of methane is CH4 + 2 O2 → CO2 + 2 H2O . A methane molecule reacts with two oxygen molecules to produce a molecule of carbon dioxide and two molecules of water. In the process, energy is released. The same basic chemistry results from the burning of gasoline in the internal combustion engine.
Competing technologies attempting to break into the transportation fuel economy — electric, hybrid, hydrogen, biofuels, natural gas — all have difficulty matching the efficiency and convenience of the internal combustion engine, because of the high energy content and convenience of gasoline. Despite huge investments and incentives by the auto industry and governments, no clear alternative to gasoline has yet emerged. But Yergin believes that gasoline’s dominance may soon wane:
One way or the other, oil’s almost total domination over transportation will either be whittled away or more drastically reduced. …
[O]ne near certainty is that the transportation system of today will evolve significantly over the coming decades. Energy efficiency and lower emissions will continue to be major preoccupations. If issues of cost and complexity and scale can be conquered, the battery will begin to push aside oil as the motive force for some of the world’s automotive transportation. But the internal combustion engine is unlikely to be shunted aside easily. The new contest may, for some time, be less decisive than when Henry Ford used his Model T to engineer victory for the internal combustion engine against the electric car.
But the race has certainly begun. The outcome will do much to define our energy world in the decades ahead in terms of where we get our energy, how we use it, and who the winners will be. But it is much too soon for anyone to take a victory lap.
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.