Published on:


 Those who visit my blog regularly know that I love charts and graphs. Below is a Sankey diagram produced by Lawrence Livermore Labs for the Department of Energy.  Sankey diagrams are named after Irish Captain Matthew Henry Phineas Riall Sankey, who used this type of diagram in 1898 in a publication on the energy efficiency of a steam engine.  The diagram below may also be viewed here.   

In the diagram, sources of energy are on the left, uses of energy are on the right. The first remarkable thing that struck me is how much energy is “rejected.” Most of the petroleum used in transportation, and most of the fuel used to generate electricity, is rejected. A huge loss by inefficiency. Avoiding even a small amount of this inefficiency would in effect create a new source of energy.

Note also the small contributions of renewable energy sources — biomass, solar, hydro and wind — to the total. And the as-yet very small contribution of natural gas to the consumption of energy for transportation.

Livermore Sankey Diagram.JPG

Published on:

For those following the Klotzman protest of EOG’s allocation well permit (our firm represents the protestants), here are the exceptions to the examiners’ proposal for decision filed by EOG and by Intervenors Devon, Pioneer, Laredo Petroleum and BP America:

EOG Exceptions to PFD.pdf

Devon et al Exceptions to PFD.pdf

Here is a link to the proposal for decision:

2013-06-25 PFD EOG Klotzman (2).pdf

EOG has called on other operators and industry organizations to file objections to the PFD, and they have responded. Letters opposing the PFD have been filed by Diamondback Energy, Halcon Resources, EP Energy, Oxy, Crimson, XTO, Burlington, Texas OIl and Gas Association, Texas Independent Producers and Royalty Owners Association, Texas Alliance of Energy Producers, Panhandle Producers and Royalty Owners Association, and Permian Basin Petroleum Association. Clearly, this PFD has hit a nerve. A typical letter, from Marathon, claims that the PFD would “prevent the drilling of countless horizontal wells throughout the State and cause tremendous, otherwise producible, reserves to be wasted and left in the ground.” The sky is falling.

Operators say that more than 100 allocation well permits have been granted to some 17 operators across the State.  According to the PFD, between April 27, 2010 and the date of the Klotzman hearing on December 3, 2012, 55 permits were approved for “allocation” wells.  During that same time period, the Commission granted 18,335 permits for horizontal wells. So for that time period, allocation well permits were three tenths of 1 percent of all permits granted. More than 4,000 permits were issued by the Commission for Eagle Ford wells alone in 2012, and some 2,000 Eagle Ford permits have been issued this year. The Commission issued a total of 22,479 drilling permits in 2012. Based on these figures, it hardly seems possible that the Commission’s decision not to issue allocation well permits would cause “tremendous reserves” to be wasted.

Published on:

The Sunset Commission’s final report on the results of its recommendations for reform of the Texas Railroad Commission can be found here. The report’s summary:

Summary of Final Results

S.B. 212 Nichols (D. Bonnen) — Not Enacted

For the second consecutive legislative session the Railroad Commission’s Sunset bill failed passage. Initially reviewed in 2011, the Railroad Commission’s Sunset bill did not pass and the 82nd Legislature continued the Railroad Commission under Sunset review for another two years.1 In 2013, the Sunset Commission again found a need for the functions of the Railroad Commission. However, with the significant and ongoing boom in oil and gas production, the Sunset Commission concluded having a more transparent and objective regulator was more important than ever. To address these concerns, the Sunset Commission recommended changing the agency’s name, limiting when Commissioners could solicit and receive campaign contributions, and requiring the automatic resignation of a Commissioner running for another elected office. The Sunset Commission also recommended several funding changes, including eliminating the statutory cap on the Oil and Gas Regulation and Cleanup Fund and creating a new pipeline permit fee to help support the agency’s pipeline safety program.

The Sunset recommendations were incorporated into Senate Bill 212. The Senate passed this bill intact, but ultimately the bill was left pending in the House Energy Resources Committee.

Although the agency’s Sunset bill failed passage for a second time, the 83rd Legislature did address a key Sunset Commission concern in other legislation by increasing, rather than eliminating, the cap on the Oil and Gas Regulation and Cleanup Fund. The Legislature also continued the agency for four years, subject to Sunset review again in 2017. One provision — requiring the automatic resignation of a Commissioner running for another elected office — was adopted by the Legislature in S.B. 219, the Ethics Commission Sunset bill, that was later vetoed by the Governor.

The following material summarizes Sunset recommendations adopted in other legislation and management actions directed to the agency that do not require statutory changes.

Continues the Railroad Commission for four years until 2017; requires the Sunset review to include an assessment of other state agencies that are able to perform the Railroad Commission’s functions; and requires the Railroad Commission to pay all costs of the review. (H.B. 1675)


Directs the Commission to review its recusal policy, and revise as necessary to ensure
Commissioner’s awareness of, and compliance with, these requirements. (management action- non statutory)

Funding Cap

Increases the statutory cap on the Oil and Gas Regulation and Cleanup Fund from $20 million to $30 million, and increases the Fund’s floor from $10 million to $25 million. (H.B. 3309)

Mineral and Land Owner Rights

Directs the Commission to study the use and development of telecommunication technology designed to increase the transparency of, and the public’s participation in, agency hearing processes and better protect the rights of mineral owners and land owners in the state of Texas. (management action – nonstatutory)

Directs the Commission to develop a fee schedule for increased charges associated with re-filing previously withdrawn applications for forced pooling or field spacing exceptions. (management action – nonstatutory)


Once again, almost all of the Sunset Commission’s recommendations were not adopted, even though comments received were almost uniformly favorable. The only significant legislation that did pass was a requirement that commissioners resign to run for another office – a bill vetoed by the Governor.

Published on:

Mose Buchele has written a series of articles, also aired on KUT, about the pipeline industry’s failed efforts to make it easier for pipelines to exercise the power of eminent domain after the Texas Supreme Court’s decision in Texas Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC, 363 S.W.3d 192, 198 (Tex. 2012), about which I have written previously. Good reading. Links are below.



Published on:

Last week I presented a paper at the Texas State Bar Advanced Real Estate CLE Conference for attorneys in San Antonio. I was asked to write a paper giving real estate attorneys a basic introduction to negotiating oil and gas leases. It might seem odd that real estate attorneys would want a primer on oil and gas leases; most people would assume that an attorney practicing real estate law in Texas would know about oil and gas leasing. And that used to be true, when the majority of attorneys had a rural general practice. General practitioners in Texas knew the basics of real estate and oil and gas law and often helped their landowner clients negotiate leases. Today, most real estate attorneys have little to do with oil and gas matters, and as practices have become more specialized the oil and gas specialty has diverged from the real estate specialty.

I was given thirty minutes to make my presentation – hardly enough time to do justice to the subject of oil and gas leases. The exercise of preparing my remarks caused me to focus on some basic concepts that I’ve not recently thought about, and I decided they would make a good topic for discussion here.

The oil and gas lease is in many ways a unique form of contract. It is the foundation of the oil and gas industry in the U.S. Because most minerals in the U.S. — unlike most of the world — are privately owned, some way had to be found for those willing to risk capital to exploit oil and gas to obtain rights to those resources. The oil and gas lease was the result. In its basic form, the oil and gas lease has remained unchanged since the early days of the industry.

The concept is simple: the mineral owner conveys the mineral estate in her land to the company that wants to exploit the minerals, for a term — a “primary term” of years, and a “secondary term,” for as long thereafter as oil or gas is produced. In that conveyance, the mineral owner reserves a cost-free interest in production – a royalty interest. The landowner thus transfers the risk and cost of development to the grantee, and retains a risk-free royalty interest in production.

The oil and gas lease is both a conveyance and a contract, and the law that has developed around the lease reflects both concepts. Its character as a conveyance has important consequences, and it is important for the landowner to understand those consequences, especially if the landowner owns both the surface and mineral estates. The mineral estate is the “dominant” estate, meaning that the owner of the mineral estate has the right, without compensation, to use so much of the surface estate as is reasonably necessary to explore for and produce oil and gas from the property. This basic idea is subsumed within the lease. The grantee in the lease acquires not only the mineral estate but also the right to use the surface estate for mineral development. This includes the right to build roads, lay pipelines, install production facilities, conduct seismic surveys, etc. And it includes the right to use groundwater for oil and gas exploration and production and the right to dispose of produced water and associated waste by drilling and operating injection wells on the property. All of these rights are implied in the grant of the mineral estate, and need not be specifically mentioned in the lease. If the landowner wants to restrict the lessee’s right of surface use in any way, those restrictions must be provided for in the lease. Absent such express contractual restrictions, the right of surface use is part of the bundle of rights granted to the lessee as part of the mineral estate.

An oil and gas lease is also a contract and enforceable as such. As the case law interpreting oil and gas leases began to develop, courts began to imply certain provisions into the lease, as a matter of contract interpretation. Courts considered that the lease imposed certain obligations on the lessee that were not expressed in the contract but were necessary in order for the parties to have the benefit of their bargain. These implied obligations are now well-recognized, and include the obligation to reasonably develop the lease and the obligation to protect the lease against drainage by wells on adjacent lands. Courts also created rules for construction of certain lease provisions. For example, leases remain in effect for a term of years and “as long thereafter as oil or gas is produced.” But what if there is a temporary cessation of production? Does the lease terminate? Faced with this question, courts developed the rule of “temporary cessation.” A lease will not terminate because of temporary lapses in production if the lessee acts diligently to restore production.

A body of law also developed around the construction of the royalty reservation in oil and gas leases. The royalty reserved in a lease is both an interest in the land – a real property interest that can be conveyed, devised, or gifted – and a contractual obligation of the lessee to make payments to the lessor. What does it mean that the royalty is “cost-free”? In Texas, courts have generally concluded that royalties are free of the costs of exploration and production but must bear their share of “post-production costs.” Again, this interpretation applies unless the parties provide otherwise in the lease agreement. How and when the royalty is calculated and paid is a source of much contention in the courts, largely because of the parties’ failure to adequately address the issue in the lease itself.

The law surrounding oil and gas leases continues to be a fascinating subject. As the technology of the exploration industry changes, new issues continue to arise and conflicts continue to result. But without this document, the oil and gas industry in the U.S. might never have been born.

Published on:

There has been a lot of discussion lately about the demand on groundwater from its use to hydraulically fracture wells, and possible contamination of wells by hydraulic fracturing and improper completion of wells.

Air Products and Chemicals is promoting the use of nitrogen foam instead of water in fracking in shallower formations.

A second study of wells in the Marcellus Shale led by Rob Jackson of Duke Universty, published in the Prodceedings of the National Academy of Sciences, found increased methane in water wells located close to recent shale wells. “Overall, our data suggest that some homeowners living < 1 km from gas wells have drinking water contaminated with stray gases," Jackson's team concluded. The study does not directly link the methane to the Marcellus wells because of the lack of data on the quality of the groundwater before the wells were drilled.

The EPA has abandoned its investigation into possible contamination of groundwater by fracking in Pavillion, Wyoming, saying that it would instead support the state’s investigation.  EPA released a draft report in 2011 that found frac fluids present in groundwater; its report was heavily criticized by the industry.

Scarcity of groundwater in the Permian Basin in West Texas has caused operators to turn to water recylcing and use of brackish (non-potable) groundwater. A recent study by UT Austin estimated that 20% of the frac water used in that area came from recycled or brackish water. The study found that in Dimmit, Webb and LaSalle Counties – all in the Eagle Ford Shale — more than 50% of total water use comes from mining, which includes fracking.

Barnhart, a small town in Irion County in West Texas, has run out of water. It’s well has run dry. The Texas Commission on Environmental Quality has listed 30 communities statewide that could run out of water by the end of the year.

A report by the Texas Water Development Board showed groundwater levels dropped significantly in Texas aquifers. In South Texas’ Carrizo-Wilcox aquifer, the principal source for frac water in the Eagle Ford, median groundwater levels dropped 4.4 feet in monitoring wells, and the average drop was 17.1 feet. One monitoring well in LaSalle County ropped some 136 feet.

Here is a good article on the relation between water resources and hydraulic fracturing:

Ceres, an environmental non-profit, has published a paper analyzing water use in fracking operations and efforts being made by industry to use alternatives to potable groundwater. It found that more than half of the wells drilled in Texas in 2011 were in areas with high or exremely high “water stress.”


Published on:

Colleen Schreiber has written an excellent article in the June 13 edition of Livestock Weekly, “Landowners Hold Off Oil and Gas Lobby on Common Carrier Bills,” describing the blow-by-blow negotiations and lobbying in the pipeline industry’s efforts to “solve” the problems created by the Texas Supreme Court’s decision in Tex. Rice Land Partners, Ltd. v. Denbury Green Pipeline-Tex., LLC, 363 S.W.3d 192, 198 (Tex. 2012).

Lined up on one side:  pipeline lobbyists supporting bills by Rep. Tryon Lewis, R. Odessa, in the House, and Robert Duncan, R. Lubbock, in the Senate, including the powerful Koch brothers, owners of Koch Enterprises.

On the other side:  Texas and Southwestern Cattle Raisers Association, Texas Farm Bureau, Texas Land and Mineral Owners’ Association, the Bass family, and plaintiffs’ lawyers.

Ultimately, all bills failed. The pipeline industry asked the Governor to add their issue to the special session but, so far at least, pipelines have been overshadowed by abortion bills and financing of higher education projects.

In Denbury, the Supreme Court surprised the pipeline industry by holding that they actually have to prove their proposed line will be a “common carrier” before they can use the power of eminent domain to condemn right-of-way. This left the pipelines, in their view, subject to interminable delays and suits by landowners unhappy with the pipeline routes, the terms of their proposed easements and the compensation being offered.

To “fix” the problem, the pipelines proposed that a pipeline’s common-carrier status be determined once for each pipeline, at a hearing held before the Texas Railroad Commission. Landowner lobbyists agreed to negotiate and agreed to consider the concept of a single hearing that would determine common-carrier status for a pipeline; but they wanted the hearing to be before the State Office of Administrative Hearings (SOAH), rather than the RRC; they wanted to be sure all landowners likely to be affected got notice of the hearing; and they wanted strict standards to determine whether a pipeline qualifies as a common carrier. In the end, the biggest sticking point was whether the hearings would be before the RRC or SOAH. Pipelines obviously favored the RRC; the landowners, believing that the RRC would not protect their interests, favored SOAH.  (Most administrative hearings related to state agencies in Texas are held before administrative judges at SOAH. The RRC is one of the few agencies that has kept the right to have hearings before its own administrative judges, called hearings examiners.)

A bill might have been hammered out, but late in the game plaintiffs’ lawyers, led by Wayne Reaud, a lawyer who made a fortune suing tobacco companies, weighed in and refused to compromise. Reaud at the time was fighting a condemnation action brought by CrossTex for a pipeline that would cross lands he owns in Jefferson County. Reaud claimed that CrossTex should not have the right to survey on his land until it proved that it is a common carrier. He sought and obtained a temporary injunction to keep CrossTex off his property. CrossTex appealed that injunction to the 9th Court of Appeals in Beaumont, and the appeal was pending when the pipeline bills were being considered. (The Beaumont court has since issued its opinion affirming the trial court’s decision to grant the injunction. The opinion can be viewed here.) The end result was that the pipeline bills died in committee and never came up for a vote in either the Senate or the House.

Underlying the debate over the pipeline legislation is the perception by those representing landowners’ interests that the RRC is not the place to have hearings on the qualifications of pipelines to exercise eminent domain, and the insistence by the pipeline interests that the RRC be the judge. The RRC has jurisdiction to enforce other laws affecting landowners’ interests, and their experience has been that the RRC is not an agency friendly to landowners’ complaints.

Published on:

The examiners who heard the Klotzmans’ protest of EOG Resources’ application for an allocation well permit have issued their Proposal for Decision in the case. A copy of the PFD can be viewed here:  2013-06-25 PFD EOG Klotzman (2).pdf  Our firm represents the protestants in the case. For my prior discussion of the case and allocation well permits, see here and here and here. The parties now have until July 10 to file exceptions to the proposal, and replies to exceptions are due within 10 days thereafter. After that, if no changes to the PFD are made, it will go before the Railroad Commissioners for their decision.

Published on:

Last Friday, the Texas Supreme Court affirmed judgment in favor of XTO in its battle with Homer Merriman over whether XTO’s well should have been moved so as to accommodate his cattle-working operation.

I wrote about this case when the Supreme Court decided to hear it. Mr. Merriman 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 Mr. 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 southwest 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 [on other lands] that are not impracticable or unreasonable.”

The Supreme Court’s opinion concluded that the court of appeals reached the right result, but it disagreed with that court’s reasoning. It first re-stated the accommodation doctrine:

To obtain relief on a claim that the mineral lessee has failed to accommodate an existing use of the surface, the surface owner has the burden to prove that (1) the lessee’s use completely precludes or substantially impairs the existing use, and (2) there is no reasonable alternative method available to the surface owner by which the existing use can be continued. 

If the surface owner carries that burden, he must further prove that given the particular circumstances, there are alternative reasonable, customary, and industry-accepted methods available to the lessee which will allow recovery of the minerals and also allow the surface owner to continue the existing use. … [A] surface owner’s burden to prove that his existing use cannot be maintained by some reasonable alternative method is not met by evidence that the alternative method is merely more inconvenient or less economically beneficial than the existing method. … Rather, the surface owner has the burden to prove that the inconvenience or financial burden of continuing the existing use by the alternative method is so great as to make the alternative method unreasonable.

The court of appeals had said that Merriman could have conducted his cattle-working operations on other lands nearby that he leased for cattle operations, which was a “reasonable alternative” under the accommodation doctrine. The Supreme Court disagreed. It said that “the court of appeals improperly considered the land leased by Merriman in detrmining whether he produced evidence that he had no reasonable alternatives to continue his cattle operations.” The question was whether he had a reasonable alternative on the 40-acre tract.

The court of appeals also said that Merriman could have used his 40 acres for other agricultural uses. The Supreme Court said that this was not the test. Rather, the test was whether Merriman had any “reasonable alternatives for conducting his cattle operations on the tract, not whether he produced evidence that he had no reasonable alternatives for general agricultural uses.”

Finally, the Supreme Court considered whether Merriman “met his burden to produce evidence that he did not have any reasonable alternatives for continuing his cattle operation, including [roundup, sorting, working and loading of the cattle] on the tract.” It held that he did not. Merriman’s evidence “did not explain why corrals and pens could not be constructed and used somewhere else on the tract; and if they reasonably could be, then his existing use was not precluded.” Merely because his existing use of the tract made working his cattle “easier,” or “works the best” for him, or was more expensive, was not enough. The Court said that Merriman’s evidence was

evidence only that XTO’s well precludes or substantially impairs the use of his existing corrals and pens, creates an inconvenience to him, and will result in some amount of additional expense and reduced profitability because to continue his cattle operation he will have to build new corrals or conduct his operations in more phases. Evidence that the mineral lessee’s operations result in inconvenience and some unquantified amount of additional expense to the surface owner does not rise to the level of evidence that the surface owner has no reasonable alternative method to maintain the existing use.

Thus, Merriman did not produce evidence sufficient to raise a material fact issue as to part of the initial element on which he had the burden of proof: that he had no reasonable alternative means of maintaining his cattle operations on the 40-acre tract.

The Court’s requirement that the landowner prove that he has “no reasonable alternative” to continue his existing use is a difficult burden to meet. But Mr. Merriman did not present a very convincing case that he could not have conducted his cattle operations on the tract because of XTO’s well.

Published on:

Terrence Henry, a writer for StateImpact Texas, has written a recent article, “Why Oil and Gas Lobbyists Were Big Spenders in Texas.” He analyzes two reports on spending on lobbyists and campaigns compiled by Texans for Public Justice. Lobbyists for energy and natural resources companies spent between $31.4 million and $62.5 million on lobbyists during the most recent legislative session, according to the report, 19% of the total of between $155 million and $328 million spent on the session. Incredible numbers. There are no limits on such spending in Texas.

Texas Railroad Commissioners were big beneficiaries of both campaign contributions and lobbying by oil and gas interests. Sunset-recommended reforms of the Commission, opposed by the Commissioners, failed to pass once again. The only RRC-related reform that did pass (but which the Governor has vetoed) was a requirement that a commissioner resign if he/she decides to run for another office.  Andrew Wheat, a researcher at Texans for Public Justice, says that’s because the oil and gas industry supported that measure:  “The [oil and gas industry] is interested in paying their bills while they’re commissioners. But they don’t want to pony up huge amounts of money every time one of these people wants to run for higher office.”

One important bill supported by the energy industry did not pass. It would have limited public participation in hearings at the Texas Commission on Environmental Quality in applications for emissions permits. The bill was opposed by communities and environmental groups. And pipeline companies’ bills to make it easier for them to exercise the power of eminent domain to condemn pipeline easements also failed to pass.


Contact Information