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Momentum appears to be gaining to increase use of compressed natural gas in vehicles in the U.S., both to decrease the nation’s dependence on foreign oil and as a “bridge fuel” to fight global warming.

  • Last Week, the Potential Gas Committee issued a report estimating that the toal U.S. natural gas resource base at year-end 2008 was 1,836 trillion cubic feet, an increase of 39% from its 2006 estimate. Most of this increase comes from newly discovered shale reservoirs. Boone Pickens said that the new estimate “is the equivalent of nearly 350 billion barrels of oil, about the same as Saudi Arabia’s oil reserves.”
  • Boone Pickens’ energy plan includes greatly expanding the use of natural gas as fuel for transportation.
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Four legislators from Colorado, New York and Pennsylvania have introduced a bill making hydraulic fracturing subject to regulation by the Environmental Protection Agency under the Safe Water Drinking Act.  Dubbed the Fracturing Responsibility and Awareness of Chemicals Act, or FRAC Act (
FRAC Act.pdf), the bill would amend the Safe Drinking Water Act to require companies to disclose the chemicals they use in their fracturing processes. The press release (
Press Release FRAC Act.pdf) from the legislators states that “It’s time to fix an unfortunate chapter in the Bush administration’s energy policy and close the ‘Halliburton loophole’ that has enabled energy companies to pump enormous amounts of toxins, such as benzene and toluene, into the ground that then jeopardize the quality of our drinking water.” (Benzene and toluene are not additives to frac fluid.)

An energy lobbying group, Energy in Depth, has denounced the bill as an “unnecessary financial burden” on the industry which could result in more than half of U.S. oil wells and one-third of gas wells being closed, and reduction in natural gas production of up to 245 billion cubic feet per year.

 

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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:

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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. 

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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:

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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.

 

 

Finley Unit.JPG 

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.”

 

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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:

  • “The United States consumes about 20.6 million barrels per day (b/d) of oil, or roughly 25 percent of global demand. By comparison, China is the second largest consumer of oil at 7.2 million b/d and Japan the third at 5.2 million b/d. Russia and Germany are fourth and fifth, respectively, at 3.1 million b/d and 2.6 million b/d. India’s oil demand also is rising quickly, increasing by almost 40 percent since 1995 to the current average of about 2.5 million b/d. The most glaring differences in demand exist in the transportation sector. U.S. road pertoleum use represents 33 percent of all road petroleum use globally, which is twice as high in percentage terms as all of Europe. China, by contrast, currently represents 5 percent of all global road petroleum use.”

 

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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.

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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.

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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.

 

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John McFarland
 Graves, Dougherty, Hearon & Moody, P.C.
401 Congress Avenue, Suite 2700
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Phone: 512-480-5618
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