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A recent editorial in the Houston Chronicle makes a good point: we should no longer think of “oil and gas” together. Their paths have diverged, at least in the US.

The prices of oil and gas used to be roughly equivalent, based on their energy value – their Btu content. But since the shale revolution in the US, this is no longer the case. Today, gas is much cheaper than oil on an energy-equivalent basis. Today, most exploration companies have moved from gas shale plays to oil shale plays, chasing the higher oil price. But gas prices have recently risen, and wells are still being drilled profitably in the Marcellus. If gas returns to $5-6/mcf, shale gas plays will return, and gas will still be much cheaper than oil.

Second, gas is a clean-buring fuel, unlike oil or coal. US emissions of greenhouse gases have declined substantially since utilities have gradually switched from coal to gas. Vehicles powered by gas have much lower emissions than those fueled by gasoline. Gas is touted as a “bridge fuel” in the transition from hydrocarbon to renewable sources of energy, because of its lighter environmental footprint.

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Information below passed on to me by a client, from a friend of a friend:

 

Following are charts and photos of a tour of Cline Shale exploration and operations yesterday afternoon. I remember the boom in the 50s and the late 70s. Those are minimal compared to the massive and very expensive boom taking place right now. I never imagined anything like this.

For instance, there are no small operators involved. Everyone leasing, building, drilling and operating has to be a major with very deep pockets. The road you will see in the first photo cost over $1 million to build. The wells are hitting 9,000 feet in this area and much deeper in other places. Each hydraulic fracturing operation (fracking) uses more than 5 million gallons of water. In just this area, railroad sidings have been built in Miles, San Angelo and Barnhart to unload sand and load oil. The railroad trains in San Angelo used to consist of a few dozen cars a week and now consist of 500 cars a day. And, really, this is just getting started.

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The drought in Texas, along with improved recyclying technology, has driven efforts to increase recycling of water used in hydraulic fracturing of wells. According to one estimate, the fracing of wells in 2011 consumed on the order of 135 billion gallons of water – about 0.3 percent of total U.S. freswater consumption. (Golf courses in the U.S. consume about 0.5 percent of all freswater used in the country.) But if you own land in the Eagle Ford field, those numbers don’t mean much. Water use in some counties is lowering the water table in the Carrizo-Wilcox aquifer, the principal source of frac water for the Eagle Ford, causing some existing wells to dry up. In West Texas, the lack of available groundwater has forced companies to look at recyclying their frac water to extend the useful life of the water they can find for fracing.

Two bills now pending in the Texas legislature – House Bills 3537 and 2992 – would require the Texas Railroad Commission to develp rules to require rthe recycling and reuse of frac water returned from wells. The Commission has recently adopted rules to make it easier for operators to recycle water. And another bill, House Bill 379, would impose a 1-cent-per-barrel fee on wastewater disposed of in commercial injection wells.

Devon Energy, a leader in recycling of frac water in the Barnett Shale, testified to Texas lawmakers that recycling is 50 to 75 percent more expensive than sending frac water to injection wells. There are now about 50,000 injection wells in Texas, and the number is growing rapidly. Recyling is much more common in the Marcellus, where injection wells are not available and water must be hauled long distances for disposal.

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Range Resources

Range Resources’ battle with the Lipskys and Alisa Rich continues, now in a confusing appeal of the trial court’s order denying the Lipskys’ and Rich’s motion to throw out Range’s counterclaim under the Texas law prohibiting so-called Strategic Lawsuits Against Public Participation, or SLAPPs.  http://www.star-telegram.com/2013/04/02/4745433/appeals-judges-return-range-suit.html

Earthquakes and Disposal Wells

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State Representative Harold Dutton, Jr. has introduced a bill in the Texas Legislature to amend Texas’ Open Beaches Act. What does this have to do with oil and gas, you may ask? Read on.

Last year, the Texas Supreme Court decided a case interpreting the Open Beaches Act, Severance v. Patterson, 370 S.W.3d 705 (Tex. 2012). The case arose because of Hurricane Rita. Carol Severance owned two beachfront houses on Galveston Island, as rental properties. Because of Hurricane Rita, erosion shifted the beach vegetation line farther landward, causing both homes to be located on the dry beach facing the Gulf of Mexico. As a result, under the Open Beaches Act, the Commissioner of the General Land Office informed Severance that she would have to remove the houses and offered her $40,000 assistance to relocate or demolish them. Severance then sued the Commissioner in US District Court claiming that the Commissioner’s action constituted a taking of her property without compensation under the Fifth Amendment of the US Constitution. Her case was dismissed, and she appealed to the 5th Circuit Court of Appeals. That court, after analyzing the case, concluded that Texas law was unclear on the matter, and it submitted “certified questions” to the Texas Supreme Court.

To understand the significance of Severance v. Patterson, it is necessary to go back a ways, to the Texas Supreme Court case of Luttes v. State, 324 S.W.2d 167 (1958). In that case, Mr. Luttes was claiming to own about 3,400 acres of “mud flats” lying on the edge of the Laguna Madre in Cameron County. The State of Texas holds title to all submerged lands along the coast, including lands within the Laguna Madre, the long, shallow lagoon that runs between the mainland and Padre Island along much of the Texas Gulf Coast. Mr. Luttes contended that these mud flats were part of his “dry land”, and not “submerged land” belonging to the State.

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Production allocation wells continue to be a simmering issue in Texas. Last Friday I attended the Ernest E. Smith Institute on Oil, Gas and Mineral Law sponsored by the University of Texas School of Law, and one of the topics presented was a paper titled “Drafting Production Sharing Agreements.” The paper included information about allocation wells.

I’ve written about allocation wells before, here and here. The Texas Railroad Commission uses that term to refer to a horizontal well that is drilled across the boundary line of two leases or units without pooling the two leases or units. Up until recently, it was assumed that the Commission would not grant a permit for such a well. Several years ago, operators began applying for permits to drill “production sharing agreement” wells. Those are wells drilled across the boundary line of two existing leases or pooled units, where the operator has obtained a “production sharing agreement” from some or all of the royalty owners to drill such a well. The production sharing agreement with the royalty owners provides that production from the well is allocated between or among the tracts crossed by the well lateral, for purposes of calculating royalties due, based on the number of feet of well lateral on each tract compared to the total lateral length of the well. In 2008, the Commissioners agreed that they would grant permits for production sharing agreement wells if at least 65% in interest of the royalty owners in all tracts on which the well would be located had signed production sharing agreements.

According to the paper submitted to the seminar, to date some 700 production sharing agreement – or “PSA” – well permits have been granted by the Commission. More than 600 of those were granted to Devon Energy.

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I recently read this astounding report from the Texas Tribune:

“In 2011, Texas used a greater number of barrels of water for oil and natural gas fracking (about 632 million) than the number of barrels of oil it produced (about 441 million), according to figures from the Texas Water Development Board and the Railroad Commission of Texas, the state’s oil and gas regulator.”

Of course wells use all of the water in the fracing process, at the beginning of the well’s life, and continue to produce oil for many years, so oil production will eventually catch up with water use. But this is nevertheless a remarkable statistic.

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UT’s Bureau of Economic Geology has issued a comprehensive report on the estimated reserves in the Barnett Shale Field. The study, funded by the Alfred P. Sloan Foundation, looked at 16,000 wells in the field. It has been submitted for peer review before publication, but a summary of the report can be found on the BEG website.

The BEG created a model with data from 15,000 wells drilled through 2010. Assuming a $4 constant gas price, the model predicts another 13,000 wells through 2030. It predicts total field production of 44 Tcf of gas through 2050. Here are two images showing results of the study:

BEG Barnett Shale 1.JPG

BEG Barnett Shale 2.JPG

 

The BEG plans to complete similar studies of the Marcellus, Haynesville and Fayetteville Shales by the end of 2013.

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The US Environmental Protection Agency has recently issued its report on greenhouse gas emissions under its Greenhouse Gas Reporting Program, which for the first time includes comprehensive reported emissions from the petroleum industry. The report covers 8,000 facilities in nine industry sectors for 2011, and total reported emissions were 3.3 billion metric tons of carbon dioxide equivalent (CO2e). Total reported emissions of CO2e from petroleum and natural gas systems were 225 million metric tons CO2e.

“CO2e” is a way to compare the global-warming potential of different greenhouse gases – their potential to trap heat in the atmosphere — by converting their emissions to the equivalent global-warming potential of carbon dioxide. Greenhouse gasses include carbon dioxide, methane (natural gas), nitrous oxide, and flourinated gases. Each of those gases has a CO2e. The CO2e of carbon dioxide is “1”. The CO2e of methane, the principal greenhouse gas emitted by the petroleum industry, is 19.1, meaning that one ton of methane has the same global-warming potential of 19.1 tons of CO2. (One ton of methane equals about 48,700 cubic feet.) The debate over whether natural gas is actually less harmful to the environment than coal involves, in part, the question whether the global-warming potential of methane leaked into the atmosphere offsets the fact that burning methane emits less carbon dioxide than burning coal. Because leaking one ton of methane has the same effect as emitting 19.1 tons of carbon dioxide, the facts concerning leaks of methane are important to that debate.

By far the largest industry sector accounting for total CO2e emissions is the power generation industry, which accounted for 67% of the total reported emissions in 2011. By contrast, the petroleum and natural gas system sector accounted for less than 7% of total emissions:

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The Texas Supreme Court denied the LaSalle Pipeline’s petition for review in LaSalle Pipeline v. Donnell Lands, leaving the San Antonio Court of Appeals’ original opinion intact. See my discussion of the case here. The trial court awarded $468 per rod $28.36/foot) for an easement for a 16-inch pipeline. The Court of Appeals affirmed, finding sufficient evidence to support the award.

The Texas Railroad Commission denied the Texas Land and Mineral Owners’ Association’s petition for a rulemaking on the Commission’s policy regarding permits for “allocation wells.” See my prior posts here and here. In their discussion concerning the petition, the Commissioners agreed that allocation wells should be addressed by rule, but they concluded that there are presently too many pending rulemakings for the Commission staff to take on more at this time. The Klotzmans’ protest of EOG’s allocation well permit remains pending, awaiting a proposal for decision from the hearings examiners.

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John McFarland
 Graves, Dougherty, Hearon & Moody, P.C.
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Phone: 512-480-5618
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