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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.


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A friend recently made me aware of a publication by the Real Estate Center at Texas A&M called “Mineral Law West of the Pecos,” written by Judon Fambrough, a lawyer who is with the Center. Judon has written much good stuff about land and mineral law in Texas, and this publication is no exception. (The Center has many good articles and publications on its website of interest to land and mineral owners.) Judon’s article contains a good summary of the history of land grants in West Texas, mineral reservations, the Relinquishment Act and “mineral-classified” land, what constitutes a “mineral,” and recent litigation over State ownership of minerals in West Texas. His article is well written and informative and should be in every oil and gas lawyer’s library. The law of Texas land grants in West Texas (and South Texas) is complex and fascinating.

Judon provides this link to maps online at the Texas General Land Office, which show tracts in West Texas subject to any mineral classification or reservation by the State:

Another good resource.

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The session is over, and the Texas legislature has failed once again to pass sunset legislation for the Texas Railroad Commission. The legislature instead authorized continuation of the RRC for another four years, with sunset review to be repeated in the 2017 legislative session.

Under Texas sunset act, every state agency must go through a comprehensive review of its functions and performance every twelve years by the Sunset Advisory Commission, a 12-member commission appointed by the Lieutenant Governor and the Speaker of the House. The RRC underwent sunset review in 2010; the report of the Sunset Advisory Commission at that time criticized the agency for failing to vigorously enforce its rules and assess penalties for rule violations, and recommended structural reforms of the agency, including replacement of the three elected commissioners with a single appointed commissioner.  But the legislature failed to pass any legislation recommended by the Commission, instead requiring that sunset review be repeated for its 2013 session.

The 2012 Sunset Commission report no longer recommended replacing the three elected commissioners with an appointed commissioner. Instead, it recommended ethics reforms, including limiting the time when commissioners could solicit campaign contributions and prohibiting commissioners from accepting contributions from any company with a contested case pending before the RRC. It also required a commissioner running for a different elective office to resign from the RRC. The commissioners vigorously opposed these recommendations and the legislation introduced to enact the reforms.

The legislation continuing the RRC does provide that the next sunset review of the RRC must consider how to dismantle the agency and assign its responsibilities to other state agencies if sunset legislation fails to pass again in four years.

Rep. Dennis Bonnen, R-Angleton, author of the interim legislation continuing the RRC, expressed his frustration at the failure of the process: “I don’t see how they can go through a third time — through sunset and no bill passes — and we continue that agency. You just can’t keep doing that. We need to have the opportunity to have a strategic, orderly plan to dismantle the agency if that’s the choice they make. It’s the obvious thing to do.” Bonnen blamed the agency’s commissioners for the failure. “I’ll be candid. All of he commissioners were against any changes for ethics. I think that’s one of our biggest obstacles. The industry’s afraid to agree with the legislators on any policy changes we’re making because they don’t want to offend the Railroad Commissioners. It’s a very bad situation.”

Rep. Bonnen claims that Commissioner Barry Smitherman plans to run for Attorney General in 2014, a claim that Smitherman does not deny or confirm. But Smitherman expressed his relief that the RRC won’t have to go through sunset review for another four years.

Meanwhile, the RRC finally passed its overhaul of oil and gas well construction rules, Statewide Rule 13, a rulemaking that has been in the works for many months. Industry and environmental advocates — in particular the Environmental Defense Fund — worked together on the rule changes, and both expressed satisfication with the result.  Scott Anderson, senior policy advisor at EDF, said that “the rule marks a huge turning point in state regulation of the safety and environmental integrity of oil and gas wells. Texas has moved back into the leadership position on regulation of oil and gas well construction. Agencies around the country, including the federal Bureau of Land Management, are likely to learn a lot from studying these rules as well as similar rules adopted last year in Ohio.” But Anderson cautioned that one big improvement is still ndeed. “For reasons we don’t understand, the commission is allowing operators to leave less space around the pipes in the lower parts of wells than experts recommend. Having enough space around these pipes is important in order to get adequate cement jobs, which are needed both for economic reasons and in order to protect the environment. EDF hopes the commission will revisit this issue in the future.”

The new rules don’t become effective until January 1, 2014.

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A recent article in the New York Times highlights the difference between “oil,” or “owal” as we say in Texas, and the heavy crude oil mined from Canadian tar sands. A major waste product of that mining is coke.  The tarry substance mined in Canada goes through an initial refining process to separate the crude from tarlike bitumen, caled “coking.” The tarry solid left from the process is called coke. It can be burned, and is an essential ingredient in making steel. The coke created from Canadian tar sands has a high sulfur content. Some of the Canadian tar sands are now being coked in a refinery in Detroit owned by Marathon Petroleum, and the coke by-product is sold to Koch Carbon, owned by Charles and David Koch. (I’m not making this up.) The Koch brothers have recently been in the news for considering an offer to buy the Los Angeles Times and the Chicago Tribune. They are also famous for supporting conservative and libertarian political causes. 

Here is the picture from the NYT article showing the stockpile of coke along the Detroit River belonging to the Kochs:


The crude oil generated by the coking process is the oil that is supposed to go through the Keystone pipeline running from Canada to the Texas coast, if that pipeline ever gets regulatory approval. According to the NYT article, Canada has 79.8 million tons of coke stockpiled. Efforts are underway to export Canadian coke to China and Mexico as a fuel. California, which also produces heavy crude that has to be coked, exports about 128,000 barrels of coke per day, mostly to China. The EPA does not permit it to be burned in the US. The Oxbow Corporation, owned by William I. Koch (a brother of David and Charles), is one of the world’s larges dealers in petroleum coke, selling about 11 million tons a year.

Here are some pictures of petroleum mines in Alberta, Canada:

Alberta oil sands 1.jpg

Alberta oil sands 2.jpg

Alberta oil sands 3.jpg

Alberta oil sands 4.jpg

This is what the raw petroleum sand looks like:

Alberta oil sands 5.jpg

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The Texas Supreme Court has recently refused to hear Friddle v. Fisher, 378 S.W.3d 475 (Tex.App.-Texarkana 2012). The court of appeals’ opinion has an interesting discussion of the duties of a mineral owner to owners of non-participating royalty interests burdening the mineral estate and of the application of the discovery rule to claims that such duties were breached.

These are the facts of the case:  In 1949, M.L. Friddle conveyed 84.7 acres in Hopkins County to Barney Martin, reserving 1/4 of the royalty. The reserved royalty interest later came to be owned by M.L. Friddle’s son Marvin.  In 1995, Barney Martin conveyed 1/4 of the royalty in the 84.7 acres to Mable Robinson, and 1/4 of the royalty to Helen Warde. The following day, Martin conveyed the land to Fred and Ruth Fisher.  Later, Marvin Friddle acquired from Mable Robinson and Helen Warde the royalty interests that were conveyed to them. So, at the time this controversy arose, the Fishers owned the land and minerals, subject to a NPRI owned by Marvin equal to 3/4 of the royalty.

In 1998, the Fishers signed an oil and gas lease on the 84.7 acres, reserving a 1/8 royalty. Valence Operating Company formed a pooled unit, the Ames-Antrim Gas Unit, and pooled the 84.7 acres into the unit. Valence drilled a well on the unit, but the well was not located on the 84.7 acres. Neither Valence nor the Fishers notified Marvin of the granting of the lease, the formation of the pooled unit, or the drilling of the well. Valence paid all of the royalty attributable to the 84.7 acres to the Fishers.

Marvin did not find out about the Ames-Antrim Gas Unit until 2008, shortly before he filed suit against the Fishers and Valence. In his suit, Marvin contended that the Fishers and Valence had a duty to notify him of the lease and the unit and give him the opportunity to ratify the lease and/or the unit so that he would share in unit production and get his 3/4 of the royalty on the portion of unit production allocated to the 84.7 acres. Marvin also claimed that the Fishers had a duty to hold his share of the royalty in trust for him until it could be paid to him.

Marvin’s suit against Valence was severed into a separate suit. The trial court granted the Fishers’ motion for summary judgment and ruled that Marvin should take nothing by his suit. Marvin appealed.

The court of appeals reversed and remanded the case for trial. The court held that the Fishers, as holders of the leasing rights in lands in which Marvin has a royalty, had a duty — the court calls it a fiduciary duty — to notify Marvin of the lease and to “hold the portion of the funds which would be payable to the holder of the NPRI as constructive trustees for the use and benefit of the holder of the NPRI.” The court relied as precedent on Andretta v. West, 415 S.W.2d 638 (Tex. 1967).

The facts in Andretta are similar to Marvin’s case. In Andretta, the Wests signed an oil and gas lease on lands in which Andretta had a royalty interest. Superior Oil Company held the Wests’ lease and an adjacent lease. Superior drilled a well on the adjacent lease, and the Wests claimed that Superior had a duty to drill an offsetting well on their property. In a settlement of that claim, Superior agreed to pay the Wests a compensatory royalty, as if the Wests had a 1/8th royalty in production from the adjacent tract. When Andretta found out about this settlement, he sued the Wests claiming 1/4th of the compensatory royalty payments being made to the Wests. The Texas Supreme Court held that Andretta was entitled to his 1/4th of that compensatory royalty. It said that, if the Wests knew the name and whereabouts of the royalty owner, “it was their duty to notify him of the [settlement] and account to him for his share of the payment as received.”

The court of appeals in Friddle v. Fisher also had to address the Fishers’ claim that Friddle had waited too long to file his suit. Under Texas law, a claim like Friddle’s – a suit for breach of a fiduciary duty — must be brought within four years of the date when the plaintiff discovered or should have discovered the breach of fiduciary duty. The court of appeals held that there was conflicting evidence in the record as to when Friddle discovered or should, in the exercise of reasonable diligence, have discovered the facts that gave rise to his claim, and that a jury should be asked to determine when Friddle should have discovered his claim.

The Fishers’ attorneys argued strenuously that the discovery rule – the rule that the four-year limitation period for bringing suit does not begin until Friddle discovered or should have discovered his claim – should not apply to his claim, based on three recent Texas Supreme Cout cases, HECI Exploration Co. v. Neel, 982 S.W.2d 881 (Tex. 1998), Shell Oil Co. v. Ross, 35 S.W.3d 924 (Tex. 2011), and BP America Production Co. v. Marshall, 342 S.W.3d 49 (Tex. 2011). In those cases, the Texas Supreme Court has held that the discovery rule does not apply to royalty owners’ claims against their lessee for additional royalties, and that the royalty owners have a duty to look after their interests and investigate whether they should be entitled to royalty payments. The court of appeals distinguished those cases on the ground that an oil and gas lessee does not owe a “fiduciary” duty to its lessor, but only a duty to act in good faith and as a prudent operator. A person owed a fiduciary duty is relieved of the obligation to diligently inquire into the fiduciary’s conduct. He is entitled to assume that the fiduciary is looking after his interest until facts to the contrary are brought to his attention. So Friddle was relieved of any duty to “diligently inquire” into the Fishers’ conduct, and the discovery rule applies to determine when he is barred by limitations from pursuing his claim.

I have previously written critically about the Texas Supreme Court’s opinions in Shell v. Ross and BP v. Marshall. I believe that the court has placed an unreasonable burden on royalty owners to “diligently inquire” into their lessee’s conduct to discover errors or misdeeds. The court is being asked to revisit this issue in another case now pending on petition for review, Hooks v. Samson Lone Star, L.P., on appeal from the First District Court of Appeals in Houston.

Many properties in Texas are burdened by non-participating royalty interests. In the early days of the oil business it was common for landowners to buy and sell NPRI’s as a way to speculate on possible future oil and gas development. In some tracts there are dozens or even hundreds of royalty owners. The standard industry practice when tracts subject to NPRI’s are leased is for the lessee to seek out the NPRI owners and request that they sign ratifications of the lease. The lessee wants the ratifications because they give the lessee the right to pool the NPRI interests in accordance with the pooling clause in the lease. Most mineral owners who sign leases on lands burdened by NPRI’s assume that their lessee will obtain those ratifications and properly account to the NPRI owners for their share of production. Even identifying and tracking down the NPRI owners is sometimes a large task, one that most mineral owners would not wish to assume. While Friddle v. Fisher does not impose that burden on the mineral owner, the case does impose some amount of obligation on the mineral owner to see that the NPRI owner is dealt with fairly.

It may be prudent for mineral owners whose interests are burdened by NPRI’s to include provisions in their leases affirmatively obligating their lessee to seek out and account to the NPRI owners, and to provide that information to the lessor so that he can assure that his obligations are satisfied.


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A study written by J. David Hughes and published in February by the Post Carbon Institute claims that shale gas reserves are vastly overstated. “Drill Baby Drill – Can Unconventional Fuels Usher In a New Era of Energy Abundance?”  A companion article by Deborah Rogers claims that the shale “frenzy” is a Wall-Street-created bubble, that “U.S. shale gas and shale oil reserves have been overestimated by a minimum of 100% and by as much as 400-500% by operators according to actual well production data filed in various states,” and that “shale oil wells are following the same steep decline rates and poor recovery efficiency observed in shale gas wells.” “Shale and Wall Street: Was the Decline in Natural Gas Prices Orchestrated?” Both are published on a website called  These nay-sayers are continuing a tradition that has followed the oil and gas industry for decades – the debate between the peak-oil advocates and those who believe we will never run out of fossil fuels.

David Hughes’ study is worth reading. He studied more than 60,000 shale wells in the US and their rates of decline, costs and reserves. Hughes concludes that more than 1,542 wells will have to be drilled each year in the Bakken and Eagle Ford plays just to maintain current production, at a cost of $14 billion per year. He estimates that it will take $42 billion and more than 7,000 wells per year to maintain current levels of production of shale gas, whereas the value of the gas produced in 2012 was only $32.5 billion. Some examples from Hughes’ study:

On overly optimistic predictions by the Energy Information Administration:

Hughes Figure 25.JPG

Hughes’ decline curve for Eagle Ford wells:

Hughes Figure 72.JPG

Hughes’ prediction of future production from the Eagle Ford and Bakken plays:

Hughes Figure 80.JPG

And on the world’s insatiable appetite for fossil fuels:

Hughes Figure 109.JPG

 Hughes’ study is mentioned in “What If We Never Run Out of Oil,” by Charles C. Mann, in the May edition of The Atlantic magazine. Mann gives a broad historical perspective to the debate over the ubiquity of fossil fuels. Mann begins by recounting his visit to the Kern River oil field in California many years ago.  One of the first and biggest oil fields discovered in the US, Kern River was discovered in 1899. In 1949, after 50 years of production, analysts estimated that 47 million barrels of recoverable reserves remained. In the next 40 years, the field produced 945 million barrels, and in 1989 analysts estimated the field’s remaining reserves at 697 million barrels. By 2009, the field had produced more than 1.3 billion barrels and remaining reserves were estimated to be almost 600 million barrels.

Mann then tells the story of M. King Hubbert, a prominent geophysicist at Shell oil in the 1950’s. In 1956, Hubbert predicted that crude oil production in the US would peak between 1965 and 1970. In 1964 Hubbert went to work for the US Geological Survey. The head of the USGS at the time, Vincent E. McKelvey, was an optimist about US oil and gas reserves, and his agency issued optimistic assessments of US oil industry’s future.  McKelvey denigrated Hubbert’s pessimistic projections and eventually forced Hubbert to resign from USGS.  Although McKelvey derided Hubbert’s theories, they proved to be correct, and the decline in US production led to the oil embargo and gas lines of the 1970’s. Jimmy Carter adopted Hubbert’s views in declaring that the planet’s proven oil reserves could be consumed by the end of the next decade. The Carter administration imposed energy-efficiency measures including gas-mileage regulation, home-appliance energy standards, conservation tax credits and subsidies for weatherization.

Mann says that the debate continues today between pessimists and optimists, Hubbertians and McKelveyans, “hammering at each other like Montagues and Capulets.” The difference between the Hubbertians and the McKelveyans is in their conception of what is a “reserve.” The Hubbertians think of reserves as a physical entity – oil in the ground. The McKelveyans think of reserves as an economic judgment: how much petroleum can be harvested from a given area at an affordable price. In fact, reserve estimates are a mixture of the two – at least if you are wanting to know “recoverable” reserves. What is “recoverable” depends on the price of the commodity and the cost of extracting it. As prices rise, recoverable reserves increase. As technology improves and costs drop, recoverable reserves increase. And vice versa.  Because there will always be some oil in the ground that is too expensive to recover at any point in time, McKeleyans say that the world’s supply of oil will never be exhausted. Thus the idea behind Mann’s article: “Will we ever run out of oil?”

And now the shale boom, and predictions that the US will soon be energy-independent. If the past is any judge, any prediction is sure to be wrong.

Mann’s article goes well beyond the peak oil debate. He explores the possibility of commercial production of methane hydrate as the next breakthrough in unconventional hydrocarbon resources. Methane hydrate is gas trapped in frozen water crystals beneath the sea bed.

Methane Hydrate.JPG

Mann says that “Estimates of the global supply of methane hydrate range from the equivalent of 100 times more than  America’s current annual energy consumption to 3 million times more.” A core sample of methane hydrate was found to contain 99.4% methane. The ice crystals in which the methane is trapped can be lit afire – burning ice.

Ice on fire.JPG

Japan has spent $700 million on methane hydrate research over the past decade. Its ship, the Chikyu, is the world’s most sophisticated research vessel. It recently tested a method of recovery of methane from methane hydrate that produced about 4 million cubic feet of gas.


Mann speculates on the global geopolitical consequences of a shift to unconventional hydrocarbon resources like shales and methane hydrate. Although it would be a relief not to rely on Middle East reserves for US energy supply, such a shift could have destabilizing results in the economies and politics of nations who even now are in the middle of unsettling developments. Mann quotes Daron Acemoglu, an MIT economist and co-author of Why Nations Fail: “Think of Saudi Arabia.  How will the royal family contain both the mullahs and the unemployed youth without a slush fund?”

The US is unique among the 62 petroleum-producing nations in allowing private entities to control most oil and gas resources. In most nations, these assets are owned or controlled by the government. Michael Ross, a UCLA political scientist and author of The Oil Curse: How Petroleum Wealth Shapes the Development of Nations (2012), says that this naturally leads to corruption. Such oil-based economies become unstable when shortfalls in oil revenues eliminate the sole, unsteady support of the ruling elite.

The world has become totally dependent on fossil fuels for its economy and well-being. As Mann says:

[E]conomic growth and energy use have marched in lockstep for generations. Between 1900 and 2000, global energy consumption rose roughly 17-fold, … while economic output rose 16-fold – as close a link as one may find in the unruly realm of economic affairs.

We depend on hydrocarbons for everything from lighting our homes to providing energy to build our computers to running our cars. Modern life would be impossible without hydrocarbons. Humankind’s appetite for energy is insatiable, and is sure to grow as developing countries continue to increase their standard of living. We need to understand and be aware of the consequences. Mann’s article is a good place to start.

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The pipeline industry bill intended to “fix” the issues raised by Texas Rice Land Partners v. Denbury Pipeline, appears to be dead in the Texas legislature. The issue: requiring pipelines that assert the power of eminent domain to prove that they qualify as common carriers. The Texas Supreme Court held in Denbury that simply filing a form with the Texas Railroad Commission would not suffice; the pipeline has to show that it will actually use the pipeline to transport oil or gas for hire. This requirement could substantially slow the condemnation process, requiring pipelines to prove their common-carrier status each time they sue to condemn a right-of-way.

The solution proposed by the pipelines: have one hearing, at the Texas Railroad Commission, to establish that a proposed new line will in fact qualify for common-carrier status. That determination will then be binding on all landowners whose property will be crossed by the pipeline. Those landowners would be given the opportunity to participate in the hearings; notice of the hearings would be given by publication in local newspapers. The Texas Farm Bureau, the forestry industry, and other landowner groups opposed the bill. Most major oil and gas asociations favored the bill.

The bill, HB 2748, was defeated Friday on a procedural point of order raised by Democrats that moved it back to committee. Rural Republican representatives were faced with a difficult decision whether to support the bill, in light of opposition by rural landowners. Time is running out before the end of the session and it may be difficult to revive the bill.

Another bill, HB 3547, would establish common carrier status by a hearing before the State Office of Administrative Hearings (SOAH). Industry representatives would prefer such hearings to be before the Railroad Commission, a friendlier venue. HB 3547 has not yet reached the floor. Similar bills in the Senate do not appear to be moving.

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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.

So why are we still using so much oil? Principally because of the transportation sector. It is expensive to convert vehicles to burn natural gas, and there is a dearth of refueling stations in the US for natural gas. If the price of natural gas remains cheap, more and more vehicles will burn it instead of gasoline.

As the public begins to better understand the differences between oil and natural gas, and as the market’s confidence grows in the US supply of gas, the stability of its relatively low price, and its more benign environmental impact, gas should make inroads into the transportation industry.

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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.

The Cline Shale is nearly 150 miles from north to south and nearly 60 miles from east to west. Reservoir engineers still think it will be the largest oil field ever discovered in the USA. The impact on cities and towns is profound. Colorado City has 4,200 residents and there are four hotels and two supermarkets under construction. At all times of the day and night, the traffic in Snyder seems like rush hour in Dallas. Motel rooms in many towns are being rented for 12 hour shifts. Nobody knows where people will live, how water will be available to drink or how to maintain roads that are being torn up by the heavy truck traffic. For now, everyone’s attitude is to sack the money while you can and kick the can down the road to solve problems some day.

In San Angelo, one of the most important events is the rodeo. This year there were no hotel rooms for the rodeo cowboys and tourists because the rooms were full of oil field workers. That used to be the biggest tourist draw in town. I guess the cowboys slept in their horse trailers with their horses since some have very nice sleeping places. The Chamber of Commerce and the hotel owners never said a word of apology. There is a brand new apartment complex west of San Angelo with hundreds of apartments and the whole thing has been leased indefinitely to Halliburton. In Midland, restaurants are closing early because they do not have the workers to stay open and are running out of food. In Big Lake, convenience stores are closing early in the day because they are out of food and fuel. I stopped at the Dairy Queen in Big Lake and the typical order being called in was for 36 hamburger baskets to go. And there is order after order like that. Every day, people with food trailers leave San Angelo and drive to Barnhart and Big Lake to feed people. I talked to a banker in Big Lake who said the best food in town is now a food trailer. I have heard that there is such a demand for truck drivers that they are receiving $10,000 signing bonuses and making $80,000 a year.

Chart of Oil Bearing Formations and Approximate Depth in Irion and Reagan Counties. The depths will vary from one part of the Permian Basin to another.



The Million Dollar Caliche Road – must be 10-15 miles long – the blue pipes are transporting water for miles from to and from holding ponds for the wells.

Cline 1.jpg


Entire hills of limestone are excavated, crushed and screened for rock to make roads and drilling pads. Look at the man standing beside the portable rock crusher. As soon as this hill is gone, then another will be crushed. The landscape is changing. On the other side of the crushed rock pile were several loaders and dump trucks which were hauling the material off almost as fast as it could be produced.

Cline 2.jpg

Long view, about 2 miles, showing 5 pads in a row. Each pad will contain 3-4 wells. Pads are huge (several acres) to accommodate the multiple wells and the fracking operations.

Cline 3.jpg

Three active drilling rigs. A few days ago there were five lined up. Notice the old pump jack on left. This ranch already had hundreds, if not thousands, of old wells. By old, I mean 30 years old. Notice red pumps and red pipes piping water to fracking operations. In some cases, the recovered frack fluids are being cleaned up and used for water flooding the old wells to stimulate secondary production.

Cline 4.jpg

A fracking operation in progress. The crane holds a manifold over the drilled well. There were several heavy-walled pipes connected to the manifold, through which pass the fracking fluids, gels and propants. Each operation requires about 5,000,000 gallons of water. That’s a problem in a part of the world with very little water to start with. It’s hard to imagine the value of all the trailers, trucks, storage facilities, pumps and other equipment at each site. The cheapest thing in the photo are the porta-potties.

Cline 5.jpg

Several wells are drilled on each pad. These are two wellheads only a few feet apart. Once the rig completes one hole, a couple of bulldozers are used to skid the rig over about 30′ where it starts another well. We saw as many as four wells per pad. Each well probably has multiple horizontal legs 9,000 feet down in the Cline Shale. Most of the horizontal legs are 1.5 miles in horizontal length. In this particular location, all the horizontal legs are north-south because the production is better than any other orientation. This type of information is determined by drilling and testing “Science Wells” which usually cost over $2,000,000 each. These “science wells” are never meant to be produced. How can you kiss off $2 million? That’s what I mean when I say that only the big boys are playing this game.

 Cline 6.jpg


Looking at a large storage tank. There are dozens of these tanks. They are so big that you can see them with Google Earth. At each tank, the water surface is roughly 5 acres and the depth is approximately 15 feet. Each tank  contains about 26,000,000 gallons or 624,000 barrels of water. The reason much much is stored is because the water must be readily available (guaranteed) to begin and maintain hydraulic fracturing operation.

Cline 7.jpg





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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.

The talk about recyling of frac water has raised an interesting legal question: whose water is it?

Groundwater is part of the surface estate in Texas. The owner of the mineral estate has the right to use so much of the surface estate – including groundwater – as is reasonably necessary to explore for and produce the minerals. Typically, an oil and gas lease grants the lessee the right to use groundwater, just as it grants the lessee the right to use the surface of the land, to explore for and develop the oil and gas under the leased property. Unless the lease provides otherwise, the lessee has no obligation to compensate the surface owner for the groundwater used. The operator may drill a water well and use that water for drilling and fracing wells on the lease, without compensation to the surface owner.

If the owner of the mineral estate also owns the surface of the land, the lease may require the lessee to compensate the lessor for use of the surface estate. In such instances in Texas, leases now often require the lessee to pay for groundwater used, at up to 50 cents per barrell or more.

Landowners in Texas also have sometimes contracted to sell their groundwater to operators for use in fracing wells. The operator, after contracting with one surface owner to obtain a groundwater supply, may build a large holding pond to store and use water for fracing of wells located on several leases in the vicinity of the pond, piping the water to its wells.

In those instances where the groundwater is sold to the operator, the operator has title to the water and should be able to recycle and use it as it pleases. But where the operator has taken groundwater under its general right to use the surface estate pursuant to its lease, the issue is less clear. The operator has the right to use the water, but may not acquire title to the water. Until recycling technology came about, the used frac water was just a waste product of the drilling operation that had to be properly disposed of. Once water is recycled, it has an economic value, and the surface owner of the property may claim that the water still belongs to it.

This is just one of the many interesting new legal issues raised by new technology in the oil field.

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