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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.

Earthquakes and Disposal Wells

Earthquakes caused by disposal wells continue to make the news. 

RRC figures show that wastewater pumped into disposal wells in Texas increased from 46 mllion barrels in 2005 to nearly 3.5 billion barrels in 2011.

Oil Spill Trial

The huge trial to determine liability for the 2010 Gulf of Mexico oil spill continues. The judge threw out all claims against Cameron, the maker of the blowout preventer on the well, finding no evidence to support any claim against it.

Keystone Pipeline

Here is a good article from the Washington Post explaining the facts and politics of the Keystone Pipeline.

CSSD Performance Standards

A coalition of exploration companies and environmental organizations has created a new orgainzation and published performance standards for drilling and fracturing horizontal wells in the Marcellus. The new organization, the Center for Sustainable Shale Development, includs as partners the Environmental Defense Fund, Chevron, the Clean Air Task Force, Consol Energy, Shell, the Pennsylvania Environmental Council, and others. The Center’s website is  Its new performance standards are here:  They include best practices for protecting water resources and eliminating use of fresh groundwater and surface waters in hydraulic fracturing; recycling of flowback and produced water; use of closed-loop systems for drilling fluids; best practices for casing and cementing of wells; reduction of venting or flaring of gases in the drilling process; emissions standards for pumps and motors used in drilling. Other companies are being encouraged to sign onto the goals of the standards.  See 

In West Texas, companies are increasingly using brackish water for fracing. 

There are increasing complaints about air quality in the Eagle Ford. 

And confusion reigns among Texas groundwater districts about if and how to regulate groundwater pumping for frac water.

Meanwhile the Obama administration has issued new proposed rules for hydraulic fracturing on public lands:

The Top Five Facts Everyone Should Know About Oil Exploration

Another good article from Forbes:  Did you know that about 40% of all seaborne cargo is oil? Also see

Exxon Oil Spill in Arkansas

A reminder that oil pipelines sometimes break:



Basses Sue Chesapeake for Unpaid Royalties

Chesapeake seems to be trying to get out of its debt problem by refusing to pay royalty owners what they are owed.;

Texas Railroad Commission

Commissioners at the Texas Railroad Commission seem to have problems getting along with each other. But they did pass new rules intended to make it easier for companies to recycle frac water. 


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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.

The original grant within which Mr. Luttes’ land lay was, like much of the land along the Texas Gulf Coast, originally granted by the King of Spain when Texas was a Spanish possession. When Texas gained its independence, it recognized the validity of land grants previously made by Spain and Mexico within its territory. Issues regarding title to original grants in Texas are decided based on the law in effect at the time the grants were made – in Mr. Luttes’ case, the law of Spain. So, in deciding Mr. Luttes’ case, the Court had to determine how the boundary between land and the sea should be determined under Spanish law in effect at the time of the original grant. The case was the first time the Texas Supreme Court had addressed this question.

The Spanish law addressing this question, as recognized by the Court, is known as Las Siete Partidas, or “The Seven Parts,” compiled in the 13th century. Spanish law declared the shore of the sea to be public property, available for all to use. A part of that law says: “and all that place is called shore of the sea insomuch as it is covered by the water of the latter, however most it grows in all the year, be it in time of winter or of summer.”  Because of its Spanish heritage, Texas has long considered its beaches public property — unlike many states whose antecedent law is the common law adopted from England, which holds that the dry beach above the ordinary reach of the tide is private land.

The Court in Luttes decided to adopt a “scientific” approach to mark the boundary between the sea and the land, borrowing from a US Supreme Court case decided in 1935 that addressed the question of the location of the shore boundary in California. The Court held that the boundary was “the line of mean higher high tide,” determined by the average of the reach of the tide each day during a seven-year tidal cycle.

The Luttes decision caused a huge controversy when it was decided, because it meant that the “dry beach,” the area between the “wet beach” and the line of vegetation — what the public understood to be its public beach — was in fact private property. If the public wanted to use the beach, it would have to wade in the water. As a result, the Legislature passed the Open Beaches Act. That Act declares that the public has an easement over the dry beach for its public use. And, since it was well known that beaches often erode, leaving homes and other structures originally built behind the line of vegation out on the beach, the Act created a mechanism for requiring removal of those structures. Private owners are never happy when this occurs, and there have been numerous cases involving the application of the act since it was passed, but until last year it was generally believed that the Open Beaches Act had solved the problem created by Luttes, at least as far as the public’s use of the beaches was concerned. That is, until Severance v. Patterson.

But what, you ask, does this have to do with oil and gas? Be patient.

So, in Severance v. Patterson, the 5th Circuit Court of Appeals asked the Texas Supreme Court three questions. The first question was

“Does Texas recognize a “rolling” public beachfront access easement, i.e., an easement in favor of the public that allows access to and use of the beaches on the Gulf of Mexico, the boundary of which easement migrates solely according to naturally caused changes in the vegetation line, without proof of prescription, dedication or customary rights in the property so occupied?”

In other words, does the public’s easement along the beach move whenever the vegetation line changes, whether by gradual erosion or sudden changes caused by storm events? The Court’s answer: No. In the Court’s majority opinion the court, clothing its opinion in the language of “private property rights,” held that “[a]lthough existing public easements in the dry beach of Galveston’s West Beach are dynamic, as natural forces cause the vegetation and the mean high tide lines to move gradually and imperceptibly, these easements do not spring or roll landward to encumber other parts of the parcel or new parcels as a result of avulsive events.” In other words, if an owner’s house becomes stranded on the beach because of an “avulsive” event — a storm — the public has no easement over the newly created beach and cannot force the owner to remove the house.  Three justices dissented from the majority opinion, arguing that:

Texas beaches have always been open to the public. The public has used Texas beaches for transportation, commerce, and recreation continuously for nearly 200 years. The Texas shoreline is an expansive yet diminishing public resource, and we have the most comprehensive public beach access laws in the nation. Since its enactment in 1959, the Texas Open Beaches Act (“OBA”) has provided an enforcement mechanism for the public’s common law right to access and to use Texas beaches. The OBA enforces a reasoned balance between private property rights and the public’s right to free and unrestricted use of the beach. Today, the Court’s holding disturbs this balance and jeopardizes the public’s right to free and open beaches.

Because of continued erosion along the Texas shore and gradually rising water levels, it is feared that the public’s right to use Texas beaches will continue to be eroded — a direct result of the Texas Supreme Court’s rulings in Luttes and Severance.

Representative Dutton’s House Bill 325 is an attempt to overturn Severance by declaring that the “public beach” is “any beach area, whether publicly or privately owned, extending inland from the line of mean low tide to the line of vegetation bordering on the Gulf of Mexico, as the line of vegetation may shift over time as a result of avulsive events or other forces of nature.” It is not clear whether his bill has any chance of passage, or whether, if passed, the Court would be willing to recognize the public beach as the bill re-defines it.

So, what does all of this have to do with oil and gas?

The boundary between the sea and the land marks not only the line between the State’s ownership of the seabed and private upland, but also the line of the State’s ownership of minerals under submerged land. Texas owns title to minerals under the Gulf of Mexico extending three marine leagues from the shore. But a large portion of Texas’ submerged lands lie within the Laguna Madre, which stretches from Brownsville to Matagorda Bay.

laguna madre.jpg


Laguna Madre is in most places very shallow, two feet or less in depth. Wind-driven tides cause huge areas of the laguna to be sometimes dry, sometimes inundated. The Intracoastal Waterway, constructed by the US Army Corps of Engineers in the 1930’s, runs the length of the laguna and allows for navigation.

There is one area of the laguna, called the “land cut,” located in Kenedy County, which is often totally exposed, from the mainland to Padre Island. It serves to separate the northern and southern segments of the Laguna Madre. In some seasons of the year it is covered with water – in other seasons it is dry mud flats. Below is an image from Google Earth of the land cut. The entire area encompasses about 35,000 acres of land.

land cut.JPG


 Beginning in about 1996, our firm represented the Texas General Land Office in a dispute with the John G. and Marie Stella Kenedy Memorial Foundation over title to the land cut. The Kenedy Foundation owns the lands to the west of the land cut, given to the Foundation by Sarita Kenedy East. The Ranch encompasses some 235,000 acres, one of the largest ranches in Texas. The Foundation argued that the land cut, under the rules for location of the shore boundary established by the Texas Supreme Court in Luttes, was dry land and part of the original Spanish and Mexican grants making up the Kenedy Ranch. The State argued that the land cut – sometimes dry, sometimes inundated – was part of the bed of the Laguna Madre, owned by the State. The fight, of course, was not over the land, a vast mud flat wasteland, but over the mineral rights to 35,000 acres along the Texas Gulf Coast.

After a jury trial, the trial court entered judgment holding that the State owned the disputed land. That judgment was upheld by the Austin Court of Appeals.  In December 2000, the Texas Supreme Court affirmed. But the Kenedy Foundation asked the Court to reconsider, and in 2001 the Court agreed to rehear the case. During the interim, several supreme court seats on the court changed hands. Finally, on August 29, 2002, the Court withdrew its prior opinion and issued an opinion reversing the courts below and holding that the entire disputed area belongs to the Foundation. Three justices dissented.

As a result of the Kenedy case the map of the Kenedy Ranch as now shown on its website now looks like this:

Kenedy Ranch.gif

In effect, the Court ruled that the “shore” of the Laguna Madre adjacent to the Kenedy Ranch lies along the edge of the Intracoastal Waterway, a man-made channel.

I’m sure that the Court in 1958, when it decided Luttes, had no idea that it was giving away thousands of acres of submerged land in the Laguna Madre, or allowing the public’s access to beaches to disappear. Nevertheless, this has been the result. With the introduction of House Bill 325, the fight over the coastal lands and beaches along the Texas shore continues.

A footnote: The author of the Luttes opinion was Justice St. John Garwood. He was the father of Will Garwood, at one time a member of our firm and later a judge on the 5th Circuit Court of Appeals. St. John Garwood was of counsel to our firm after he left the court, and he was still coming to the office when I joined our firm in 1978. Justice Garwood’s most notable opinion during his time on the court was Luttes. His wife, Ellen Clayton Garwood, was a member of the prominent Clayton family of Houston and was known for having donated $2.5 million to conservative groups backing the Nicaraguan contras during Ronald Reagan’s presidency.  She testified in support of Lt. Col. Oliver North in the contra hearings before Congress. Her father was William L. Clayton, who served as Under Secretary of State in the Truman administration.

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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.

More recently, operators have convinced the Commission staff to grant drilling permits for wells crossing two or more leases or units even if the operator has no pooling or production sharing agreements with the royalty owners. The Commission refers to such wells as “allocation wells.” According to the seminar paper, permits have been granted for 98 allocation wells. The Commission is granting such permits even though it has no rule authorizing the granting of the permits.

As I have earlier written, our firm represents a landowner who has protested a permit EOG applied for to drill an allocation well. A hearing has been conducted on that protested permit, and the parties are awaiting a proposal for decision from the hearings examiners.

The seminar paper, written by Mickey Olmstead of the McElroy Sullivan firm here in Austin, and Robert Jowers of the Shannon Gracey firm in Houston, is in large part a brief arguing that allocation wells should be permitted by the Commission. The paper does not mention the EOG protested permit application.

I have learned since the EOG permit hearing that there is at least one pending lawsuit by a mineral owner against EOG for drilling an allocation well. I have also seen a permit granted for an allocation well based on the operator’s misrepresentation to the Commission that the well will be drilled on a pooled unit, even though the operator has no authority to pool the two leases across which the horizontal well will be drilled. I have also been told that operators are applying for permits for allocation wells without disclosing to the Commission that the well will be an allocation well. So it is difficult if not impossible to determine how many allocation wells have in fact been drilled.

The right to agree – or not agree – to the pooling of one’s royalty interest has been long-recognized by Texas courts, and is a significant right for all royalty and mineral owners in Texas. Texas has no forced-pooling statute like those in Oklahoma and Lousiana that force mineral owners into pooled units against their will. (Texas’ Mineral Interest Pooling Act does allow forced pooling under limited circumstances.) Recently there was substantial opposition to a bill pending in the Texas legislature, HB 100, that arguably grants operators the right to force-pool royalty interests. In my opinion, if operators are granted permits to drill allocation wells, despite having no pooling agreements with the royalty owners, the rights of royalty owners to negotiate pooling provisions in their leases will be seriously eroded.

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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.

The Tribune article reports that a study by the UT Bureau of Economic Geology published in January “found that the amount of water used statewide for fracking more than doubled between 2008 and 2011. The amount is expected to increase before leveling off in the 2020s. The study’s lead author, Jean-Philippe Nicot of the University of Texas, has calculated that in 2011, nearly a quarter of the water used in Dimmit County went toward fracking. He projects that the figure will rise to about a third in a few years.”

The Tribune has also published a good article on the uneven responses of Texas groundwater districts to operators’ use of groundwater, that you can read here.

Fracing continues to make news elsewhere:

The California Department of OIl Gas and Geothermal Resources is considering regulations covering fracing that are being criticized by the industry and environmentalists:



In New York, which has had a moratorium on fracing since 2008, the governor is still considering whether to lift the ban. The state’s health commissioner is preparing to issue his recommendation, which the governor said will be key to his decision. The New York State Assembly recently voted to extend the moratorium through 2015.

A group of artists and actors led by Yoko Ono and Sean Lennon have started up their own campaign to ban fracing in New York, called Artists Against Fracking. Several of them have produced a music video of Sean Lennon’s song “Don’t Frack My Mother:”  “Don’t frack my mother, cos I ain’t got no other. You can do anything that you want to do, but please don’t frack my mother.” Yoko Ono then pitches in: “Don’t frack me, don’t frack me.”

Only in America.

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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:

US CO2e emissions pie chart.JPG

EPA’s estimate of total U.S. greenhouse gas emissions from all sources (including, for example, vehicles and house furnaces) for 2011 is 6.822 billion metric tons CO2e.

Here is EPA’s summary of greenhouse gases from petroleum and natural gas systems in the U.S.:

EPA GHG Report Summary.JPG

Here is a breakdown by percentage of total:

GHG pie chart.JPG


“Petroleum and Natural Gas Systems” includes the entire path of oil and gas from production through distribution:

NG Systems illustration.JPG



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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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The E&P industry is continuing to face public criticism of its use of fresh groundwater in fracing wells and its failure to disclose the chemicals added to frac water.

On February 5, the Investor Environmental Health Network (IEHN) issued a press release announcing that shareholders have filed resolutions with Cabot O&G, Chevron, Exxon Mobil, EOG Resources, ONEOK, Pioneer Natural Resources, Spectra Energy, Range Resources and Ulta Petroleum challenging the companies “to quantifiably measure and reduce environmental and societal impacts” of their exploration activities. The resolutions focus on water issues, asking the companies to disclose the amount and sources of water used, how they track and measure naturally occurring radioactive materials (NORM) in frac water, whether and to what extent the companies use closed-loop systems in handling frac water, and what efforts are being made to reduce the amount of fresh water used. Shareholder proposals were filed by Calver Investments, Green Century Capital Management, the New York City Office of the Comptroller, the New York State Common Retirement Fund, the Sisters of St. Francis of Philadelphia, and Trillium Asset Management. IEHN and the Interfaith Center on Corporate Responsibility published a report in 2011, “Extracting the Facts: an investor guide to disclosing risks from hydraulic fracturing,” intended to list and encourage best risk management practices by E&P companies, including reducing and disclosing all toxic chemicals, minimizing fresh water use by substituting non-potable sources, and using closed-loop systems to store waste waters.

Last week, New York Comptroller Thomas DiNapoly announced that the state’s pension fund had reached an agreement with Cabot O&G to disclose its practices for minimizing the use of toxic chemicals in frac fluids. DiNapoli withdrew his shareholder proposal submitted for Cabot’s upcoming proxy statement. DeNapoli has negotiated similar agreements with Hess, Range Resources and SM Energy.

Halliburton, which provides frac fluids for the industry, has developed a “green” frac fluid called CleanStim that uses only food-industry additives. Halliburton production manager Nicholas Gardiner said that Halliburton has developed a chemistry-scoring system for fracfluids, with lower scores being better. CleanStim has a zero score, he said, but is “relatively more expensive” than many traditional fracking fluids. Terry Engelder, a geologist at Penn State, said: “Eventually industry would like to end up with a mix of just water, sand, and food-grade additives. Companies are learning to deal with fewer and fewer additives.”

The Texas House Energy Resources Committee held a hearing last week about fracing and water use. Industry spokesmen testified that they are using more brackish water and reusing flowback frac water; recycling water; and covering their retention ponds that store fresh water to limit evaporation. A spokesman for Fountain Quail Water Management said that 900 million gallons of flowback water have been recycled back to freswater in the Barnett Shale over the past nine years. He also announced formation of the Texas Water Recycling Association. A Devon Energy spokesman saidd that Devon had recycled about 700 million gallons of frac water since 2005. He said it costs 50 to 75% more than disposing of the water by injection. NBC News reported on a new water desalination technology that can clean up brackish water so that it can be used in fracing.

Meanwhile, Texas’ law on disclosure of chemicals in frac fluds has come under criticism because of its trade-secret “loophole.” A Bloomberg report said a sample of frac fluid disclosures from 370 wells reported in August 2012 showed that Baker Hughes averaged 9.1 non-disclosed ingredients per well, Halliburton averaged 9.3, and Superior Well Services averaged 32.5. Lon Burnam, the Democratic state legislator who co-authored the law, said that “this disclosure bill has a hole big enough to drive a truck through.”


On another topic: a final good-bye to Aubrey McClendon, who has resigned from Chesapeake, the company he founded. He receives a nice parting gift of $45.2 million over the next four years and $33.5 million in restricted stock. He was previously removed as Chairman of the Board because of heavy criticism of alleged conflicts of interest and the company’s poor market performance. It will be interesting to see how Chesapeake survives without him. While much of the criticism of his tenure is undoubtedly deserved, his huge contribution to the natural gas boom of the last ten years should not be forgotten.

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The Texas Supreme Court has agreed to hear arguments in a case that could have important implications for landowners and oil and gas exploration companies: Merriman v. XTO Energy, No. 11-0494. Merriman’s attorneys are asking the Court to reverse the 10th Circuit Court of Appeals, at Waco, which they contend has consistently mis-interpreted the Supreme Court’s rulings on the accommodation doctrine.

The “accommodation doctrine” is a court-made doctrine relating to the mineral owner’s right to use the surface estate to drill for and produce minerals. The mineral estate is the “dominant estate,” meaning that the owner of the mineral estate has the right to use so much of the surface estate as is reasonably necessary for exploration and development of the minerals, without compensation to the surface owner for such use. (This includes the right to use groundwater for oil and gas operations, even though the groundwater belongs to the owner of the surface estate.) The Supreme Court has held that, notwithstanding the mineral owner’s right to use the surface, the mineral owner must under some circumstances “accommodate” the surface owner’s existing use of his land. The doctrine requires a balancing of the interests of the surface and mineral owner. In 1993, the Supreme Court said: “if the mineral owner has reasonable alternative uses of the surface, one of which permits the surface owner to continue to use the surface in the manner intended (especially when there is only one reasonable manner in which the surface may be used) and one of which would preclude that use by the surface owner, the mineral owner must use the alternative that allows continued use of the surface by the surface owner.” Tarrant County Water Control & Impr. Dist. No. 1 v. Haupt, Inc., 854 S.W.2d 909, 912 (Tex. 1993).

Homer Merriman, the plaintiff in this case, owns 40 acres in Limestone County. When he bought the land, the seller reserved the mineral estate and the land was then subject to an oil and gas lease. Merriman built his home on the land. Although he works full-time as a pharmacist, Merriman also runs cattle. He leases land in Limestone County for grazing, and once a year he uses his 40 acres to round up and work his cattle, with portable pens that are assembled for the operation and then taken down. The rest of the year he grazes cattle on the 40 acres, where he also lives.

In 2007, XTO Energy approached Merriman and told him it intended to drill a well on his tract. Merriman objected to the proposed well location, arguing that it would prevent him from using the 40 acres for his cattle working operations. XTO discussed with Merriman moving the location to the southewest corner of his tract, where Merriman said it would be acceptable, but XTO ultimately decided not to accommodate Merriman’s request. Merriman then sued XTO seeking an injunction to prevent the drilling of the well at its chosen location. Despite the suit, XTO drilled the well. The trial court granted summary judgment for XTO, and the Waco Court of Appeals affirmed, holding that Merriman “has alternative uses of his land that are not impracticable or unreasonable. Merriman further has alternative methods of conducting his cattle operation that are not impracticable or unreasonable.”

(The well XTO drilled on Mr. Merriman’s tract, the Beachcomber Unit 2 – 11 Well, is a Cotton Valley well located on a 703-acre pooled unit. It was the 10th well drilled on the unit. There are now 18 wells on the unit, including a horizontal well, all producing from the Cotton Valley formation. The 2-11 Well has to date produced almost 1 billion cubic feet of gas.)

Merriman’s lawyers argue that the Waco Court of Appeals has held Meriman to too-high a burden of proof. They say that Merriman didn’t have to prove that he had no other possible uses of his land, but only that the mineral owner’s proposed use would prevent him from continuing his current use of the property and that XTO had an alternative location that would allow his use to continue.

The Supreme Court last wrote about the accommodation doctrine in 1993. Since then, horizontal drilling has been developed and drilling has moved into more urbanized areas. Conflicts between surface and mineral owners’ rights to use land have increased. Merriman’s attorneys urged the court to take up his case both to straighten out this and prior opinions of the Waco Court of Appeals on the subject and to provide more certainty as to the meaning and application of the accommodation doctrine. It will be interesting to see if the Court decides to give Merriman another chance to prove his case, more than five years after he filed it.

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A client recently suggested that I should write about landfarming – the practice of disposing of drilling mud and cuttings by spreading it over land.

Drilling mud is the common term for the fluid used in the process of drilling a well. It is made up of a mixture of clay (bentonite) in a base of either water, diesel or mineral oil. It also contains an organic material such as lignite to stabilize the slurry and a material such as barite to increase its density. The drilling mud is circulated through the wellbore – pumped down the inside of the drill stem, through the drill bit, and up the outside or annulus of the hole as the well is being drilled. The drilling fluid carries the cuttings made by the drill bit back up and out of the hole, and it helps to cool the drill bit. The clay also coats the outside of the open hole to help seal off porous geologic strata. The drilling fluid is circulated through a pit or tank, where the cuttings settle out, and re-injected into the hole.  Usually an earthen “reserve pit” is constructed for this purpose.

The actual content of drilling mud varies with conditions in the hole and the formations being drilled. In the Eagle Ford, for example, water-based mud is typically used for the vertical section of the hole, and oil-based mud is used for the horizontal section.

After drilling is completed, the drilling mud and cuttings in the reserve pit must be disposed of. These wastes are exempt from federal regulation, and state regulations vary. Landfarming of water-based mud is a generally accepted method of disposing of the contents of the reserve pit in most states.

In Texas, oil and gas exploration and production is regulated by the Texas Railroad Commission, and its rules regarding disposal of drilling fluids are at 16 Texas Aministrative Code Section 3.8, commonly called Rule 8, or “The Pit Rule.” That rule defines “landfarming” as “a waste management practice in which oil and gas wastes are mixed with or applied to the land surface in such a manner that the waste will not migrate off the landfarmed area.”

In general, Rule 8 allows wastes remaining in reserve pits to be disposed of either by burial on-site or by landfarming on-site. But the rule requires the consent of the surface owner for landfarming:

RRC Rule 8 (16 TAC, Part 1, Sec. 3.8):

(3) Authorized disposal methods.

    (C) Low chloride drilling fluid. A person may, without a permit, dispose of the following oil and gas wastes by landfarming, provided the wastes are disposed of on the same lease where they are generated, and provided the person has the written permission of the surface owner of the tract where landfarming will occur: water base drilling fluids with a chloride concentration of 3,000 milligrams per liter (mg/liter) or less; drill cuttings, sands, and silts obtained while using water base drilling fluids with a chloride concentration of 3,000 mg/liter or less; and wash water used for cleaning drill pipe and other equipment at the well site.

    (D) Other drilling fluid. A person may, without a permit, dispose of the following oil and gas wastes by burial, provided the wastes are disposed of at the same well site where they are generated: water base drilling fluid which had a chloride concentration in excess of 3,000 mg/liter but which have been dewatered; drill cuttings, sands, and silts obtained while using oil base drilling fluids or water base drilling fluids with a chloride concentration in excess of 3,000 mg/liter; and those drilling fluids and wastes allowed to be landfarmed without a permit.

First, the RRC does not require a permit for on-lease disposal of water-based drilling fluids. If the waste is to be disposed of by burial, the drilling fluids must be “dewatered” before burial. The rule defines “dewatering” as “to remove free water.”

Second, if the operator wants to dispose of water-based drilling mud by landfarming on the lease, it must have the permission of the landowner, and the fluids must have a chloride (salt) content of less than 3,000 mg/l.

There are also commercial landfarming operations that take spent drilling mud and dispose of it for operators. Those operations do require a permit from the RRC, and many such permits have been granted. A list of recent permits can be found here. he RRC has specific requirements for such permits, including testing the soil and the drilling fluid for chloride content and heavy metals. A recent story about a criminal investigation of such a commercial operation raises questions about how well the RRC regulates such sites.

Note that disposal of reserve pit contents by burial does not require consent of the surface owner. Unless the oil and gas lease prohibits disposal by burial, the operator will be able to bury the pit contents over the objection of the surface owner. If the mineral owner also owns the surface estate, the lessee may seek to negotiate the right to landfarm pit contents in the lease itself. If the surface owner does not own any minerals, the operator may offer to compensate the surface owner for the right to landfarm pit contents.

Texas A&M’s AgriLife Extension Service has published a good summary of the risks and hazards of landfarming pit wastes, which can be found here. Among A&M’s conclusions:

- Oil may be contained in water-based drilling mud, part of the materials produced during the drilling operations. Excess amounts of oil  – in excess of 1% of the volume of the waste disposed of – are generally toxic to plants.

- Chlorides (salts) in drilling fluid can be detrimental to soils. Soil is generally considered salt-affected or “saline” when the electrical conductivity of the saturated paste extract exceeds 4 millimhos per centimeter.

- Drilling fluids can also contain boron, arsenic, barium, chromium, copper, lead, nickel and other heavy metals that can be harmful in certain concentrations.

A&M recommends that any agreement to allow landfarming should specify testing protocols for possible harmful elements, both in the soil and in the drilling fluids, by a qualified professional; specification of the proper rate of application, and possibly requirements for application of soil amendments to promote treatment of the waste; requirements for mixing the waste into the soil; and requirements for re-seeding and reclamation when the landfarming is complete, possibly with a required bond to assure performance.

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