The Texas Supreme Court has been asked to review a case decided by the Eastland Court of Appeals, Lesley v. Veterans Land Board, that raises important questions about the duty of a mineral owner to owners of non-executive mineral interests. If the Court decides to take the case, the outcome could have important implications for future development of mineral interests in urbanized areas of Texas.
The important facts in Lesley are as follows:
A study (
Armendariz Study.pdf) published last February by Al Armendariz, an engineering professor at Southern Methodist University, concluded that gas drilling in the Barnett Shale contributes about as much air pollution to the D-FW area as emissions from cars and trucks. Dr. Armendariz’s study was financed by the Environmental Defense Fund. Dr. Armendariz concluded that in the nine counties included in the D-FW metroplex area, gas drilling produced about 112 tons per day of pollution, compared with 120 tons per day from vehicle traffic. Dr. Armendariz suggested that pollution from drilling activities could be greatly reduced by requiring vapor recovery units on tank batteries and “green completions” of wells to prevent gas from being vented when a well is being completed.
Representatives of the industry quickly refuted Dr. Armendariz’s conclusions, arguing that his facts were all wrong.
As landowners have become more sophisticated in their negotiations of oil and gas leases, they have begun to insist on the inclusion of a “continuous operations” or “continuous drilling” clause in their leases. The idea behind such clause is that the lessee should have a reasonable time to fully develop the leased premises, after which the lessee should release that portion of the leased premises not necessary for the production of the wells it has drilled.
There is no “standard form” of continuous operations clause. Generally, a continous operations provision should address the following:
The Texas Railroad Commission handed down an interesting order last August that may have broad application for operators’ use of Texas’ Mineral Interest Pooling Act to force unleased mineral owners into pooled units. In Docket No. 09-0252375, Finley Resources applied under the MIPA to form a pooled unit in the Barnett Shale consisting of 96.32 acres, for the drilling of a horizontal well. The proposed unit is in an urbanized area with numerous lots, and Finley was evidently unable to get all lot owners to sign leases. A plat of the proposed unit is shown below. As can be seen from the plat, there are a lot of unleased lots (the white spaces) in the proposed unit.
Under the MIPA, the operator seeking to form the unit must make a “good faith offer” to unleased owners before filing an MIPA application to force them into the unit. Finley offered the unleased lot owners the right to receive a 1/5th royalty and a 4/5ths working interest, which means that 45ths of those owners’ share of production from the well would bear its share of the drilling and operating costs of the well. After studying the matter for a year, the Railroad Commission approved Finley’s application. One unusual aspect of the order is that the unleased owners suffer no “risk penalty.” In most MIPA applications, a party who has refused to join the unit voluntarily must bear its share of the drilling costs plus a “risk penalty,” not to exceed 100% of the drilling and completion costs, before participating in revenues from the well. The Commission’s order in Finley allows the unleased owners to participate in revenues as a working interest owner once the operator has recovered 100% of drilling and completion costs, with no “risk penalty.”
Last week I attended an Energy Syposium sponsored by South Texas Money Management, Ltd. in San Antonio. One of the speakers was Amy Myers Jaffe, who is the Wallace S. Wilson Fellow in Energy Studies at the James A. Baker III Institute for Public Policy at Rice University and associate director of the Rice University Energy Program. Ms. Jaffe is co-author of ”
U.S. Energy Policy FAQ- The U.S. Energy Mix, National Security and the Myths of Energy Independence.pdf” published by the Institute in 2008. A good read. Excerpts:
Boone Pickens’ efforts to promote natural gas as an alternative to gasoline in vehicles seems to be gaining momentum. In a column published by the Huffington Post, Pickens said that the recent advances in extraction of natural gas from shales is a “game-changer.” “One study estimates that we have enough natural gas to satisfy current demand for the next century.” Pickens reports that H.R. 1835, the NAT GAS Act, has strong bipartisan support in Congress. the NAT GAS Act provides incentives for installation of compressed natural gas (CNG) fueling stations and use of CNG in large trucks and fleet vehicles.
Natural gas gives off 25% less carbon dioxide than oil for the same amount of energy produced. About 1/3 of total U.S. carbon dioxide emissions come from burning of gasoline in internal combustion engines. For a good summary of the use of CNG, go to the U.S. Department of Energy’s website on Energy Efficiency and Renewable Energy.
Although Texas leads the nation in natural gas production, it is behind ten other states in the number of CNG fueling stations.
Royalty owners should be aware that they are entitled to severance tax refunds on gas wells drilled in certain “tight sand” formations, including the Barnett Shale. If a field is designated as a “tight sand,” Texas law provides for a reduction in severance tax from 7.5% to 2% for a period of ten years, or until the operator has recovered one-half of the well’s drilling and completion costs, whichever comes first. But the operator must apply for this exemption to the Texas State Comptroller’s office after the well has been completed. Until the exemption is granted for the well, the operator pays severance tax at the 7.5% rate, and once the exemption is granted the Comptroller refunds the excess tax paid to the operator. The operator should then pass on to the royalty owners their share of the refund, since the royalty owner bears his/her share of the severance tax. This refund could occur several months after production first commences.
According to Gene Powell’s Barnett Shale Newsletter, there are 1,452 Barnett Shale wells in the “pending file” at the Texas Railroad Commission. Wells in the pending file have not yet been assigned a lease code number. Until a lease number has been assignd by the Railroad Commission, the operator cannot file for a tight sand exemption to the Comptroller. Powell says that the 1,452 pending wells have been producing for an average of eight months, so the operators of those wells are entitled to severance tax refunds of millions of dollars, once the paperwork is done.
Royalty owners should inquire with their lessees as to the status of the lessee’s severance tax exemption. The additional royalty resulting from the exemption should be 5% of the gas royalties previously paid, from date of first production.
Conveyances of minerals in Texas usually describe the interest conveyed or reserved as an interest in “oil, gas or other minerals.” Texas courts have struggled mightily to try to discern what the parties meant by the term “other minerals.” If the parties did not specifically name a particular mineral, such as coal or uranium, did they intend that substance to be included in their reference to “other minerals”?
Making the matter more complicated, the Texas Supreme Court has changed its mind on how to approach the problem. At one point, the Court adopted a “surface destruction test” to determine whether a substance was intended to be a “mineral.” Under this rule, the Court reasoned that the parties would not intend to sever ownership of a substance from the surface estate if the commercial way to mine the mineral was by strip mining, so a near-surface substance would not be considered a “mineral.” Then the Court decided that such a test was not workable, and it adopted (but only for reservations or conveyances of “other minerals” after the date of its opinion) a different test, the “ordinary and natural meaning” test. Under this test, a substance is a mineral if it is within the “ordinary and natural meaning” of the word “mineral.” In effect, each substance must be tested by litigation to determine if it is a “mineral” within the ordinary and natural meaning of that term. Once a court has decided that a particular substance is a mineral under this test, it is a mineral for all reservations and conveyances of “oil, gas and other minerals” to which the test applies..
Because of all of the confusion about the term, I have created a short-hand decision tree to use when looking at a conveyance or reservation, to help me remember how to apply these tests. My decision tree is below.
Below is an interesting chart published by the U.S. Energy and Informaton Administration, showing how the U.S. used energy in the U.S. in 2007:
The sources of energy are on the left, the sectors of the economy that consume energy are on the right. The lines connecting supply sources and demand sectors show which sectors use which sources of energy. For example, petroleum represents 39.8% of the total supply of energy in the U.S. Seventy percent of that petroleum is used for transportation. Petroleum is the source of 96% of all sources of energy for the transportation sector. The transportation sector consumes 29% of all energy consumed in the U.S.
The chart reveals how natural gas is used in the U.S.: 34% in the industrial sector, 34% in the residential and commercial sector (as fuel to heat and cool homes and buildings), 30% to generate electricity. Most electricity is used by residential and commercial buildings, so in reality electricity is an intermediate demand sector. If it is eliminated as a demand sector, 61% of total demand would show as consumed by residential and commercial buildings. Natural gas would supply 14.8% of total energy used in residential and commercial buildings, either directly for heating and cooling or indirectly through its use to generate electricity.
The Texas Railroad Commission has denied Chesapeake Energy’s request for permission to produce its Ramey 1H well in Tarrant County, because the well was drilled in violation of RRC spacing rules. Chesapeake drilled the horizontal well with a 3,553-foot lateral, even though its permit was for a lateral of only 1,839 feet. The RRC ordered Chesapeake to plug back the well so as to comply with the permit. The problem was that the wellbore passed wihin 330 feet of an unleased tract, violating the Barnett Shale field rules that require all wells to be located at least 330 feet from the boundary of the lease or unit. Kevin Cunningham, regional counsel for Chesapeake’s southern division, said that the ruling “would have the negative effect of rendering a significant amount of gas” unrecoverable under Chesapeake’s leases. For the story in the Fort Worth Star-Telegram, click here. Situations like those faced by Chesapeake will drive the debate for forced-pooling legislation in Texas.
