December 16, 2014

The Oil and Gas Lease -- Part III: the Leased Premises

An essential element of any oil and gas lease is a description of the land to be covered by the lease. The test for a legal description is that it must contain, or make reference to recorded documents that contain, a description of the land of sufficient specificity that a surveyor could locate the property on the ground with reasonable certainty.

The lease itself can contain a metes and bounds description from a survey, or (more commonly) it can refer to an earlier recorded document that contains a metes and bounds description of the property. Sometimes descriptions have to be cobbled together from two or more other descriptions. For example: "All of that certain 100 acres of land described in deed from John Doe to Robert Smith recorded at Volume 99, page 99 of the deed records of Karnes County, Texas, save and except 10 acres of land described in deed from Robert Smith to Mary Jones recorded at Volume 100, page 100 of the deed records of Karnes County, Texas."

There are other ways to adequately describe a tract. The test is whether the surveyor can use the description to locate the property.

The requirement that the lease contain an adequate legal description comes from the Statute of Frauds. That statute in Texas is in Texas Business and Commerce Code, Section 26.01. It provides that any agreement regarding land, including an oil and gas lease, must be in writing and must contain a description of the property. The original Statute of Frauds was passed by the British Parliament in 1677 as "An Act for Prevention of Frauds and Perjuries." Every state has a version of this law.

The minerals covered by an oil and gas lease can be limited by depth. An oil and gas lease can cover only certain defined depths - for example, from the surface of the ground to 5,000 feet subsurface -- or certain known formations - for example, the Eagle Ford formation.

Although lease forms generally cover all "oil, gas and other minerals," it is better practice for the lease to cover only "oil, gas and associated hydrocarbons and other substances produced with oil and gas." The land may have other mineral deposits like coal or uranium, and there is no reason for the lease to cover such other minerals.

Most lease forms contain a clause like the following:

This lease also covers and includes all land owned or claimed by Lessor adjacent or contiguous to the land particularly described above, whether the same be in said survey or surveys or in adjacent surveys, although not included within the boundaries of the land particularly described above.

Such a clause is referred to as a "Mother Hubbard" clause. (I'm not sure how it got that name.) Care should be taken if this clause is included. If the Lessor owns other land adjacent to the leased premises that is not intended to be leased, it should either be stricken or limited. The purpose of the clause is to include small strips of land and mineral interests under adjacent roads that are owned by the Lessor but are not included in the description of the leased premises. A more narrow Mother Hubbard clause might read:

This lease also covers and includes any narrow strips of land and adjacent roads owned or claimed by Lessor adjacent or contiguous to the land particularly described above, whether the same be in said survey or surveys or in adjacent surveys, although not included within the boundaries of the land particularly described above.

Even if the Lessor does not own the entire mineral estate in the lands to be lease, an oil and gas lease almost never describes the interest owned by the Lessor. The title work done prior to acquiring an oil and gas lease may not be complete, and the Lessee wants to be sure that the lease covers the entire interest owned by the Lessor even if the title work done to quantify the Lessor's interest is wrong.  So the lease reads as if the Lessor owned the entire mineral estate. If the Lessor owns less than all of the minerals, the "proportionate reduction clause" in the lease takes care of the problem. That provision typically states something like the following:

If this lease covers less than all of the oil and gas in the leased premises, then the royalties and other monies provided herein to be paid to Lessor shall be reduced in the proportion that the interest in the oil and gas owned by Lessor bears to the entire fee simple mineral estate in the leased premises.

Landowners should be confident before they sign a lease that they agree with the Lessee's conclusions as to what interest the landowner has in the minerals to be leased. If the landowner is unsure, she should get the title information from the company upon which it based its conclusions, and satisfy herself that the computation of her undivided interest is correct.

December 8, 2014

New Texas Railroad Commission Rules on Pipeline Permits

The Texas Railroad Commission has adopted amendments to its pipeline permits rule, 16 TAC Sec. 3.70. The amendments require pipeline companies to submit documentation to support their claim that they will operate the line as a common carrier or gas utility.

In Texas, pipelines have the right to condemn pipeline easements for lines that are common-carrier or gas-utility lines. Until the Supreme Court's decision in Texas Rice Land Partners v. Denbury in 2011, pipelines assumed that all they had to do in order to exercise the right of eminent domain was file a form at the RRC - a Form T-4 - stating that the proposed line would act as a common carrier or gas utility. In Denbury, the court said that filing the form is not enough.

The court in Denbury first held that a pipeline does not acquire condemnation authority merely by obtaining a permit from the Railroad Commission and subjecting itself to that agency's jurisdiction as a common carrier. The court then held that in order for a pipeline to have condemnation power it must serve a public purpose, and to serve a public purpose, "a reasonable probability must exist, at or before the time common-carrier status is challenged, that the pipeline will serve the public by transporting gas for customers who will either retain ownership of their gas or sell it to parties other than the carrier." Once a landowner challenges its right to exercise eminent domain, "the burden falls upon the pipeline company to establish its common-carrier bona fides if it wishes to exercise the power of eminent domain."  The court said that the question of whether the pipeline is dedicated to a "public use" is ultimately a judicial question.

The rule amendments adopted by the RRC last week were proposed by the pipeline industry and were apparently an attempt to address the problems created for them by the Denbury decision. If a pipeline company wants to classify a proposed new line as a common-carrier or gas-utility line, it must include in its permit application a sworn statement "providing the operator's factual basis supporting the classification and purpose being sought for the pipeline," and "documentation to provide support for the classification and purpose being sought for the pipeline ...."

The RRC received many comments to the proposed rule, and its discussion of those comments reveals much about the RRC's intent in adopting the rule amendments. The RRC's discussion makes clear that it does not intend to get involved in the Denbury debate:

A T-4 Permit to Operate an intrastate pipeline in Texas is literally and specifically a permit to operate a pipeline. It is not a permit to construct a pipeline, nor is it authorization for a pipeline operator to exercise eminent domain in the acquisition of pipeline right-of-way.

The permitting process does not determine property rights. ... Litigation over the rights of a property owner or a pipeline's easement is not a Commission matter; it is a courthouse matter.

The Commission disagrees with assertions made by [Texas Southern Cattle Raisers Association] and other commenters that the Court in Denbury suggested the Commission should expand its processing of applications for T-4 permits to encompass investigation and adversarial testing of, particularly, the common carrier assertions made by T-4 applicants. In fact, the Court stated, "the parties point to no regulation or enabling legislation directing the Commission to investigate and determine whether a pipeline will in fact serve the public."

The new permitting process requires a pipeline operator to substantiate the basis for the classification sought. ... Property owners will know the basis on which a pipeline operator claims common carrier status much earlier in the permitting process.

The rule amendments, and the RRC's responses to comments, can be found here:

adopt-amend-3-70-common-carrier-120214-SIG.pdf

Denbury has given landowners the ability to challenge pipeline companies' assertions of eminent domain authority. That has slowed the process of pipeline right-of-way acquisition and made the process more expensive for pipelines. If pipeline companies intended these rule amendments to address those issues, I'm not sure they succeeded.

 

 

 

December 2, 2014

The Oil and Gas Lease -- Part II: The Primary Term

In Texas, an oil and gas lease grants to the lessee the fee mineral estate in the leased premises for the term of the lease. The lease provides for an initial term during which the lessee need do nothing in order to keep the lease in effect -- called the "primary term." Thereafter, the lease terminates unless the lessee is producing oil or gas or conducting operations in an effort to discover and produce oil or gas. If the lease remains in effect beyond the primary term, the remaining time the lease is in effect is called the "secondary term." A typical lease will provide that

"This lease shall remain in effect for a term of three (3) years (the primary term) and as long thereafter as oil or gas is produced from the leased premises or operations, as provided herein, are being conducted on the leased premises."

The primary term can be one month or ten years or more. Today, most leases provide for a three-year primary term. If no production or operations take place during the primary term, the lease terminates automatically and the mineral estate reverts to the lessor.

It is not necessary to obtain a release of the lease from the lessee in order to terminate the lease. It is, however, a good practice to request a release from the lessee to record in the county records, in order to give notice that the lease is no longer in effect.

It used to be common practice to include in the lease a provision for payment of "delay rentals." A delay rental clause provides that the lease will terminate at the end of each year during the primary term unless the lessee either commences operations or production or pays the lessor a delay rental, which keeps the lease in effect for another year during the primary term. Under an "unless" delay rental clause, the lessee has no obligation to pay the delay rental, and the lease expires if there is no production or operations and the delay rental is not paid. Delay rentals are usually expressed as a number of dollars per acre.

Today most leases are "paid-up" leases, meaning that all payments necessary to keep the lease in effect during the primary term have been paid. Such leases contain no delay rental clause.

Instead, it is now common for lessees to request an option to extend the primary term. Such a clause provides that the lessee has the option to extend the primary term by making an additional payment to the lessor prior to the end of the primary term. A provision for an option payment has similar effect as a delay rental clause, but is expressed differently. A typical offer might be for a three-year paid-up lease with a two-year option. Usually, the option payment is the same amount as the bonus paid for the initial execution of the lease. The option payment must be tendered to the lessor during the primary term in order to avoid lease termination.

November 26, 2014

The Oil and Gas Lease - Part I

I got the idea for starting this blog from a presentation I made at a meeting of the Texas Land & Mineral Owners' Association, titled "Checklist for Negotiating an Oil and Gas Lease." TLMA posted the outline of my presentation on its website. I soon began receiving calls from people who had found the article on the net. I had no idea that the article had found its way to the net, but the popularity of the checklist led me to believe that landowners might profit from other articles of interest to them on matters related to oil and gas exploration and development.

The oil and gas lease is the foundational document on which the oil and gas industry in the US is based. Its form and provisions have been modified and shaped over the years to respond to changing industry practices and developments in the law, but its essential form has remained unchanged since the latter half of the 19th century. It is one of the most commonly used and successful legal documents in US commerce.

So, I thought it would be a good idea to write a few posts focused on the oil and gas lease, of which this is the first.

The basic concept and form of the oil and gas lease was developed in Pennsylvania, shortly after Edwin Drake drilled the first commercial oil well in Cherrytree Township, near Titusville, Pennsylvania, in 1859. The well was drilled to 69.5 feet at a cost of $3,000, and produced 12 to 20 barrels a day, but was never profitable and ceased production in 1861. But it started the first oil boom in the US.

Drake Well.png

Drake is the man on the right, in front of his well.

Drake drilled his well under an agreement with the owners of the land, the Brewer and Watson farm. The agreement provided that the landowners "demised, leased and let" the land "to bore, dig, mine, search for and obtain oil, salt water and other minerals," and "to take, remove and sell such" for a term of 15 years, at a "rental" (royalty) of "one-eighth of all oil as collected from the springs." The lease provided that "if lessees fail to work the property for an unreasonable length of time, or fail to pay the rent (royalty) for more than 60 days, the lease to be null and void."

Drake's form of "lease" was adapted from lease agreements developed for the purpose of allowing the mining of salt brine through the drilling of wells. Salt mining agreements allowed the lessee to drill a well to produce brine that would then be evaporated and processed into salt. The agreements typically provided for payment to the landowner of a portion of the salt obtained from his land, usually every twelfth barrel.

An 1862 case decided by the Supreme Court of Pennsylvania is one of the earliest decisions involving oil rights. The dispute involved a salt mining lease. The lessee had discovered oil in the process of drilling for salt, and the question presented was, to whom did the oil belong?  The court held that the well produced both brine and oil, and it was necessary to separate the oil from the brine in order to produce salt, so the oil belonged to the lessee.

The first printed form of oil and gas lease was by a Mr. J.A. Heydrick of Oil City, Pennsylvania. His first lease form was published in about 1870. His Oil Lease No. 3, published in 1880, is recognizable as the basic form of oil and gas lease still in use today. It granted a lease for a term of 15 years "and so long thereafter as oil or gas can be produced in paying quantities." Heydrick's OIl Lease No. 4 Form became the standard oil and gas lease form in Pennsylvania.

For many years after leases began to appear, courts struggled with the legal nature of the rights granted to the lessee. Today, in most states -- including Texas --- courts agree that the lease grants to the lessee a fee simple determinable in the mineral estate in the land. "Fee simple" is the legal term for ownership. The word "determinable" means that the estate will terminate and revert to the lessor at some time in the future, when production has ceased. So the term "lease" is misleading. An oil and gas lease actually grants title to the mineral estate for the term of the lease. The lessor reserves a royalty interest --- also a real property interest --- in production for the term of the lease. So the lease creates two different real property interests in the minerals -- the ownership of the oil and gas, sometimes called the "working interest" or the "mineral leasehold estate," which belongs to the lessee, and the royalty interest reserved by the lessor. Both are interests in land and treated as such under the law.

Next installment - the essential terms of the oil and gas lease.

November 19, 2014

The Episcopal Church and the Texas Supreme Court

On August 30, 2013, the Texas Supreme Court decided two cases involving the Episcopal Church of the United States. Last week, the U.S. Supreme Court refused to hear the cases, making the results final. (In case you're wondering, this has nothing to do with oil and gas. The cases are of interest to me as an Episcopalian.) The two cases were basically a fight over ownership of church property. The parties engaged some of the most powerful firms and lawyers in the state, and multiple amicus briefs were filed. And the cases grapple with the right to free exercise of religion guaranteed by the First Amendment of the U.S. Constitution.

There are about 4.5 million Episcopalians in the U.S. -- fewer than the number of Baptists, Methodists, Mormons, Lutherans, or Presbyterians. Episcopalians, however, are often some of the elite and most powerful members of society in the U.S. The Episcopal Church in America was founded in 1789 and is a part of the Anglican Communion, which has about 80 million members worldwide. The Church is associated with and has its roots in the Church of England, founded by Henry VIII when Pope Clement VIII refused to approve the annulment of Henry's marriage to Catherine of Aragon.

The two cases decided by the Texas Supreme Court last year, The Episcopal Diocese of Fort Worth v. The Episcopal Church, and Masterson v. The Diocese of Northwest Texas, have their genesis in the consecration of Gene Robinson by the Diocese of New Hampshire in 2004 -- the first openly gay bishop in the Episcopal Church. In response, the Diocese of Fort Worth voted in 2007 and 2008 to withdraw from the Episcopal Church and enter into membership with the Anglican Province of the Southern Cone, a group of Anglican churches in South America. And the Diocese claimed to still own the properties of the churches within the Diocese of Fort Worth. (Three churches in the Diocese did not agree with the Diocese's action and withdrew from the Diocese; the Diocese transferred property used by those churches to them.)

Meanwhile, in San Angelo, the Episcopal Church of the Good Shepherd voted (53 to 30) to withdraw from the Episcopal Church and the Diocese of Northwest Texas and to form a new church, the Anglican Church of the Good Shepherd. And it claimed to own its church property.

In both cases, the trial court, after hearing the parties' arguments, ruled in favor of the Episcopal Church, holding that the Fort Worth Diocese and the Church of the Good Shepherd could not keep church property when they left the Episcopal Church. The Texas Supreme Court reversed in both cases, holding that they could.

The Episcopal Church argued that it was a "hierarchical" church, meaning that it is structured with a central organization -- the General Convention of the Episcopal Church -- at the top, Dioceses -- geographic regions headed by a Bishop -- below that, and individual churches, or parishes, at the bottom. It argued that all church property is held by each individual parish church in trust for The Episcopal Church, and that any congregation which severed its ties with The Episcopal Church lost its right to manage the Church's property. The Canons of The Episcopal Church provide that "All real and personal property held by or for the benefit of any Parish, Mission or Congregation is held in trust for this Church and the Diocese thereof in which such Parish, Mission or Congregation is located. The existence of this trust, however, shall in no way limit the power and authority of the Parish, Mission or Congregation otherwise existing over such property so long as the particular Parish, Mission or Congregation remains a part of, and subject to, this Church and its Constitutions and Canons."  When Good Shepherd Church in San Angelo was formed, it agreed in its petition for formation that its members were "conscientiously attached to the Doctrine, Discipline and Worship of the Protestant Episcopal Church in the United States."

The majority opinion in the Good Shepherd case agreed that the First Amendment to the U.S. Constitution "severely circumscribes the role that civil courts may play in resolving church property disputes," and prohibited civil courts from inquiring into matters concerning "theological controversy, church discipline, ecclesiastical government, or the conformity of the members of a church to the standard of morals required of them."  It quoted the U.S. Supreme Court's prior decision that "whenever the questions of discipline, or of faith, or ecclesiastical rule, custom, or law have been decided by the highest of church judicatories to which the matter has been carried, the legal tribunals must accept such decisions as final, and as binding on them."

The majority of the court nevertheless held that title to church property was a matter of state law, not ecclesiastical law, and that, under Texas law, the church properties belong to the individual churches and are not held in trust for the benefit of The Episcopal Church. Two justices dissented.

Disputes within church organizations arise from time to time, resulting in schisms and fights over church properties. Protestant churches divided during the Civil War. Churches have disagreed over ordination of women. Last week, the Anglican Communion voted to allow women to be appointed as bishops.

The relation between church and state also pops up in other ways -- for example, the recent dispute over application of provisions of the Affordable Care Act to church-affiliated hospitals. Courts will continue to struggle with these issues as long as the Constitution stands and citizens continue to worship their gods.

November 12, 2014

The Fall in Oil Prices

The news is filled with stories predicting the effect of falling oil prices on US production.  Good news for the economy, bad news for the Texas oil and gas industry. Will the rig count fall? Will companies go into bankruptcy? Only time will tell.

The answer may depend on OPEC. OPEC countries produce about one-third of the world's total oil each month. OPEC countries have about 80 percent of the world's oil reserves. Predictions of OPEC's demise are greatly exaggerated. But US production has increased to almost 9 million barrels a day, close to Saudi Arabia's production. Texas is responsible for a big part of that increase:

Texas production chart.PNG

Clearly the increased US production, combined with the predictable decline in demand and the slowdown of China's and Europe's economies, is affecting the world oil price. OPEC convenes on November 27, and pundits are guessing what it will do. On October 29, OPEC's Secretary-General Abdalla El-Badri, cautioned calm, after a conference in London: "We don't see really fundamental changes in the supply side or the demand side.  Unfortunately everyone is panicking. The press is panicking, consumers are panicking. We really should think and see how this will develop."

El-Badri has a point. Looked at over the long term, as shown below, this may be but another adjustment in world prices.

EIA gas and oil price chart.PNG

Not all OPEC countries are the same. Some countries will be squeezed by oil prices below $80:

OPEC price squeeze.PNG

So far, the falling oil price appears to have had little effect on drilling activities in Texas. The Texas Petro Index published by the Texas Alliance of Energy Producers reached 312.3 in September, up 6% over last September. The Baker Hughes rig count in Texas was 902 in September, up from 837 rigs in September 2013. But the US rig count dropped by 4 rigs to 1,925 for the week ended November 7, although horizontal rigs gained 9 to 1,362.

One analyst, Gavekal Dragonomics, says that, if oil prices continue to fall, "drilling activity is likely to decline." But the negative effects on the energy sector will be outweighed by the positive effect on US consumers. Lower prices will lift net exports. And each one-cent drop in gasoline prices puts $1 billion in the pockets of consumers over a one-year period.

Dr. Harold Hunt, professor at the Texas A&M Real Estate Center, recently presented an analysis of how falling oil prices affect the Houston economy. Here is a link to the Powerpoint of his presentation: Hunt_S_TX_College_Oct__2014___.pdf  Dr. Hunt notes the declining cost of drilling in the Eagle Ford, lowering the break-even price of oil:

Well Costs - Hunt.PNG

 

Down-sizing of well spacing has also maximized the value of Eagle Ford acreage:

Well spacing.PNG

Dr. Hunt also notes the increased rates of initial production in the Eagle Ford, but also the increase in decline rates of those later wells:

EIA increased production rates over time.PNG

 

His conclusion: 80% of shale oil resources in the US can make money with oil at $50 to $80 per barrel:

Hunt break-even.PNG

Much depends on where the acreage is in the play. There are good sections and bad sections in the Eagle Ford, as in all fields. Those producers on the margins will suffer at $80 prices. And investors may be more wary of putting their money in areas with higher risk.

November 3, 2014

Trespassing on the Mineral Estate

Last week the San Antonio Court of Appeals decided Lightning Oil Company v. Anadarko, No. 04-14-001152-CV, a case involving "mineral trespass."  What is interesting about the case is what the court did not decide.

Lightning Oil Company owns two oil and gas leases covering 3,250 acres within the Briscoe Ranch in Dimmit County. The Briscoe Ranch owns the surface but not the minerals in this 3,250 acres. To the south of Lightning's leases is the Chaparral Wildlife Management Area, a wildlife sanctuary managed by Texas Parks and Wildlife Department. TPWD owns the surface and 1/6 mineral interest in the Chaparral WMA. The Light family (some of whom own Lightning Oil) own the other 5/6 mineral interest. Anadarko holds oil and gas leases on the Chaparral WMA.

The TPWD lease to Anadarko prevents use of the surface of the Chaparral WMA for oil and gas wells except with TPWD consent, and says that Anadarko must use off-site drilling locations "when prudent and feasible." Anadarko made an agreement with Briscoe Ranch to use the surface of the Ranch to drill horizontal wells under the Chaparral WMA. The first location Anadarko chose is located on the land covered by the Lightning Oil Company leases. So Anadarko proposed to drill a horizontal well from a surface location on Lightning's lease; the well would penetrate the Eagle Ford formation on Lightning's lease, but no perforations, or "take points," in the well would be located on Lightning's lease.

Lightning sued Anadarko to prevent it from drilling its well, and it sought a temporary injunction to stop the well while the case was pending. After a hearing on Lightning's application for temporary injunction, the trial court refused to grant the injunction, and Lightning appealed.

The opinion of the San Antonio Court of Appeals (Lightning Oil Co v. Anadarko.pdf ) affirmed the trial court, holding that Lightning had failed to prove a probable, imminent and irreparable injury if Anadarko is allowed to drill its well.

To obtain a temporary injunction, the plaintiff must prove that it can probably prevail when a trial on the merits of its case is held, and that it probably will suffer irreparable injury if the temporary injunction is not granted to maintain the status quo until trial on the merits.

Lightning alleged that Anadarko's well would trespass on Lightning's mineral estate. Anadarko argued that its well would not result in a trespass.  The Court of Appeals decided not to address that question. Instead, it focused on whether Lightning's evidence showed that it would probably suffer irreparable harm if the well were drilled. After reviewing the parties' testimony, the Court held that Lightning's evidence failed to show probable irreparable harm. The testimony, said the Court, only showed a "potential" for injury, and Lightning failed to show that the potential injury would not be "susceptible to quantification and compensation."

The more interesting question in this case is the one the Court of Appeals elected not to address -- whether the drilling of Anadarko's well would constitute a trespass.  In my experience, operators routinely obtain permission from the surface owner to locate well pads off-lease, but do not consider it necessary to obtain consent of the mineral owner. The general theory is that the owner of the surface estate owns the land from the surface to the center of the earth; the owner of the mineral estate owns only the oil, gas and other minerals under the land. Under this theory, a mineral trespass can occur only if a well actually produces (or perhaps harms) the oil, gas or other mineral under the land. Following this line of reasoning, drilling a well through a formation capable of producing oil or gas would not constitute a mineral trespass. And the right to grant permission to use the surface estate for an off-lease location, under this theory, belongs to the surface owner.

October 29, 2014

Texas Tribune Unique Look at Texas Oil Boom

The Texas Tribune has created an unusual interactive website with stories about life in the oil patch and the effect of the boom on the lives of those who live and work in the areas affected. Take some time and explore it.  http://apps.texastribune.org/shale-life/eagle-ford-air/ 
October 27, 2014

Chesapeake v. Hyder

Chesapeake has asked the Texas Supreme Court to hear its appeal of Chesapeake v. Hyder, decided by the San Antonio Court of Appeals in March of this year. The Supreme Court has asked the parties to file briefs on the merits, and Chesapeake filed its brief last week. Although the Court has not yet agreed to hear the case, its request for briefs is an indication that the Court may do so.

I wrote about the Hyder case when it was decided last March. Since then, the U.S. Court of Appeals for the 5th Circuit has decided two other Chesapeake cases, Chesapeake v. Potts and Chesapeake v. Warren, ruling in Chesapeake's favor in both cases. All three cases involve deduction of post-production costs from royalties. Multiple cases have been filed against Chesapeake challenging its post-production-costs deductions, because of its aggressive method of calculating those costs. In all three cases, Chesapeake relies heavily on a Texas Supreme Court case decided in 1996, Heritage Resources v. NationsBank. The Texas Supreme Court has not discussed its opinion in Heritage since it was decided. Hyder may be its opportunity to do so.

The oil and gas lease in Hyder provides that "the royalty reserved herein by Lessors shall be free and clear of all production and post-production costs and expenses." It also states that "Lessors and Lessee agree that the holding in the case of Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and provision of this Lease." The Court of Appeals held that the lease prohibited Chesapeake from deducting transportation costs.

The Court of Appeals opinion has an interesting discussion of Chesapeake's structure for marketing and selling its gas. The owner of the lease is Chesapeake Exploration, LLC. Chesapeake Operating, Inc., drills and operates the wells and pays the royalty. Chesapeake Energy Marketing, Inc., buys the gas from Chesapeake Operating (as agent for Chesapeake Exploration). Chesapeake Midstream Partners, LP gathers the gas from the leases and delivers it to pipelines owned and operated by unrelated parties. Those pipelines in turn deliver the gas to purchasers, who pay Chesapeake Energy Marketing, Inc.

A recent investigative report by Pro Publica describes how Chesapeake spun off its subsidiary, Chesapeake Midstream Partners (which became Access Midstream), in the process raising $4.76 billion.  According to the report, Chesapeake sold its network of gathering lines in Pennsylvania, Ohio, Louisiana, Texas and the Midwest to Access, and entered into an agreement with Access for Access to gather and transport Chesapeake's gas. Over a ten-year period, Chesapeake pledged by this contract to pay Access enough in fees to repay Access's purchase price plus a 15 percent return on the investment. The agreement also provides for Access to pay Chesapeake for use of certain Chesapeake equipment. According to the report, the result of these transactions was to greatly increase Chesapeake's cost of gathering its gas, to an average of 85 cents per mcf. That gathering cost greatly increased the deductions on Chesapeake's royalty owners' checks. In effect, it could be argued that Chesapeake has monetized some of its gas reserves by locking itself into a long-term gathering agreement with Access, in exchange for a $4.76 billion payment from Access, and in the process created an inflated gathering charge which can be passed on to its royalty owners.

In June, attorneys in Pennsylvania filed suit against Chesapeake, seeking certification of a class action on behalf of Pennsylvania royalty owners, alleging that the system used by Chesapeake for marketing its gas constitutes a violation of the Racketeer Influenced and Corrupt Organizations Act, or RICO. (Complaint can be viewed here.) The lawsuit claims that  "defendants, under the guise of Chesapeake's subsidiaries' agreements with lessors, exploited deductions language from the lease agreements to, among other things, shift repayment of Chesapeake's off-balance sheet loan from Access Midstream to the lessors."

October 20, 2014

Steadfast v. Bradshaw - Supreme Court and NPRI's

Last week the Texas Supreme Court heard oral arguments in Steadfast Financial v. Bradshaw, No. 13-0199. The case presents the court with another opportunity to grapple with an issue that Texas courts have struggled with since the court first addressed it in 1937 - what duty does the owner of the mineral estate owe to a non-participating royalty owner?

The term "non-participating royalty owner" is the name commonly given to a royalty interest in minerals created by a grant or reservation in a deed.  "Non-participating" is really redundant; it means that the holder of the royalty estate has no right to lease the mineral estate or to receive any bonus for a lease.  In fact, that is true of all royalty interests. A better name for this type of royalty interest might be "fee royalty interest," to distinguish it from a royalty interest reserved by the mineral owner in an oil and gas lease.

The owner of a fee royalty interest, having no right to lease or to drill wells, is dependent on the owner of the mineral estate out of which his/her royalty interest must be paid; the royalty interest has no value unless the mineral interest is leased and wells are drilled. In recognition of this fact, court decisions have imposed a duty on the mineral owner to protect the royalty owner's interest. How this duty is defined, and in what situations the duty is imposed, have been issues Texas courts have struggled with for many years. The cases that have addressed this issue over the years show how the common law develops -- very slowly, and with varied results for the litigants involved.

In Steadfast, Steadfast Financial owned the surface and mineral estates in 1,800 acres of land in Hood County. In 2006, Steadfast entered into a transaction with Range Resources: it sold the surface estate to Range for $8,976,600, and it granted an oil and gas lease to Range providing for a 1/8th royalty. At the time, Betty Lou Bradshaw owned a royalty interest in the 1,800 acres that she had inherited from her parents. When her parents sold the land in 1960, they reserved a royalty interest of 1/2 of the royalty; in other words they were entitled to 1/2 of any royalty reserved by the mineral owner in any oil and gas lease covering the 1,800 acres. 

When Ms. Bradshaw learned about the Steadfast-Range transaction, she sued Steadfast and Range. She claimed that the going royalty rate for oil and gas leases in Hood County in 2006 was 1/4th, and that Steadfast had a duty to her to get the best royalty it could obtain. She alleged that Steadfast and Range had conspired to breach Steadfast's duty to her, and that Range should be liable for its participation in Steadfast's scheme. She argued that Steadfast got a much better deal on its sale of the land to Range by agreeing to reduce the royalty rate in its lease to Range from 1/8 to 1/4.

The trial court threw out all of Ms. Bradshaw's claims, but the Fort Worth Court of Appeals held that she was entitled to a trial and remanded the case to the trial court.  Bradshaw v. Steadfast Financial, 395 S.W.3d 348 (Tex.App.-Fort Worth 2013). Steadfast appealed to the Texas Supreme Court, which agreed to hear the case. You can view the oral arguments in the Supreme Court here.

The Texas Supreme Court first considered the mineral owner's duty to a royalty interest owner in Schlittler v. Smith, 101 S.W.2d 543 (Tex. 1937), where it described the mineral owner's duty as one of "utmost fair dealing."  One of the most important Supreme Court cases on the topic is Manges v. Guerra, 673 S.W.2d 180 (Tex. 1984), involving the infamous Clinton Manges. Manges leased the minerals under his ranch in Duval County to himself for 1/8th royalty, and then sold the lease, reserving an additional 1/8th royalty for himself. The Court held that in doing so he breached his duty to the Guerras, who owned a royalty interest in the ranch. The Court held that Manges breached his "duty of utmost good faith" to the Guerras.

More recently, the Supreme Court has grappled with the mineral owner's duty to royalty owners in In re Bass, 113 S.W.3d 735 (Tex. 2003) and Lesley v. Veterans Land Board, 352 S.W.3d 479 (Tex. 2011). In Bass the Court held that a mineral owner has no duty to the royalty owner to grant an oil and gas lease. In Lesley the Court appeared to backtrack on what it had held in Bass, holding that a mineral owner does have a duty to a royalty owner to lease under some circumstances.

The lawyers arguing for Steadfast and Range said that Steadfast had no duty to Ms. Bradshaw to obtain the highest royalty rate it could, and that Steadfast should have the right to enter into a lease with 1/8th royalty and the highest bonus it could negotiate, even though the result would be to lessen Ms. Bradshaw's share of production. Bradshaw's attorney said that such a rule would be contrary to the substantial body of case law that had recognized a duty of "utmost good faith" owed by the mineral owner to its royalty owner. Questions from some members of the Court indicated that they were reluctant to require Steadfast to negotiate the best royalty it could obtain. If the Court decides to rule against Ms. Bradshaw, it could show an increasing reluctance by this Court to impose implied covenants or higher standards of conduct in the relationship between mineral and royalty owners in Texas.

October 9, 2014

Supreme Court Refuses to Hear Appeal of Trail Enterprises v. City of Houston

Trail Enterprises' efforts to collect an inverse condemnation judgment against the City of Houston have finally come to an end. The US Supreme Court has refused to hear its case. Trail Enterprises' story is instructive to parties who may be thinking of challenging cities' decisions to ban drilling within their boundaries.

The dispute has a long history.  Lake Houston is a major source of drinking water for the City of Houston. In 1967, the City passed an ordinance restricting the drilling of new oil and gas wells in a "control area" around the lake. That restriction has remained in place except for an eleven-month gap in 1996-97, when the lake was annexed into the City and the City passed a new ordinance protecting the lake. 

In 1995, Trail Enterprises, an owner of mineral interests in the restricted area around the lake, sued the City, claiming that the 1967 ordinance restriction amounted to a "taking" of the mineral interests in violation of the US Constitution. The trial court dismissed that suit, and the Houston Court of appeals affirmed. Trail Enters., Inc. v. City of Houston, 957 S.W.2d 625 (Tex.App.-Houston [14th Dist.] 1997, writ denied). In 1999, Trail sued again, this time arguing that the City's 1997 ordinance resulted in a taking of its property. The trial court held that the ordinance did not constitute a taking. This time the Houston Court of Appeals reversed and remanded the case for a trial. Trail Enters., Inc. v. City of Houston, 2002 WL 389448 (Tex.App.-Houston [14th Dist.] Mar. 14, 2002, no pet.). But the parties decided to dismiss that case.

Finally, in 2003, Trail, joined by other mineral owners, filed suit a third time. In 2005 a trial was finally held and a jury awarded the plaintiffs $19 million. But the trial judge dismissed the case on the ground that the plaintiffs had never applied to the City for a drilling permit.  That order was again appealed. The appeal was transferred to the Waco Court of Appeals, which affirmed the trial court's dismissal. Trail Enters., Inc. v. City of Houston, 255 S.W.3d 105 (Tex.App.-Waco 2007). Trail appealed to the Texas Supreme Court, which reversed and remanded the case back to the trial court. City of Houston v. Trail Enters., Inc., 300 S.W.3d 736 (Tex. 2009). This time, the trial court, after another evidentiary hearing, entered judgment against the city for $17 million.

The City appealed again, and in an opinion in 2012 the Houston Court of Appeals held that no "compensable taking" had occurred and reversed the trial court's judgment.  City of Houston v. Trail Enters., Inc., 377 S.W. 3rd 873 (Tex.App.-Houston [14th Dist.] 2012). Trail sought review by the Texas Supreme Court, but in October last year that court refused to hear the case.  And this week, the US Supreme Court also refused to hear Trail's appeal. After 19 years, Trail's efforts have finally come to naught.

Why such a tortuous fight through the courts? One reason is the very murky law of inverse condemnation. The Fifth Amendment to the US Constitution provides: "nor shall private property be taken for public use, without just compensation." The US Supreme Court has struggled mightily over the years to define what this means. Its seminal case on the matter is Penn Central Transp. Co. v. New York City, 438 U.S. 104 (1978).  In that case, the court attempted to define when a government's restriction of use of private property was so onerous as to require the government to pay the property owner -- when governmental restrictions amount to a "taking" of private property. The court's decision in Penn Central laid out a three-part test. Under this test, a court must evaluate a regulatory takings claim based on (1) the economic impact of the regulation, (2) the owner's "reasonable investment-backed expectations," and (3) the character of the regulatory action. Those words don't mean much until fleshed out by subsequent cases, and the factors are fuzzy and subjective. So inverse condemnation cases like Trail Enterprises become very fact-specific analyses, and the subjectivity of the test sometimes allows the biases of court judges to emerge.

I'm no expert on takings law. But recent developments in Texas and other states, centered around municipalities' increasing efforts to restrict drilling for oil and gas within their limits, may end up in takings cases like Trail Enterprises. The mineral owners' extreme difficulty in getting a final determination of their claim in Trail, and the multiple appellate opinions grappling with the takings issues, is an indication of the hurdles that other mineral owners may face in seeking compensation for cities' restrictions on drilling that affect the value of their mineral interests. In Texas, the City of Denton has a proposition on the November ballot:  "Shall an ordinance be enacted prohibiting, within the corporate limits of the City of Denton, Texas, hydraulic fracturing ...."  See "In Texas, a Fight Over Fracking," in the New York Times, Oct. 8.  Already a group of mineral owners has sued Denton over its temporary moratorium on drilling within city limits. If Denton's referendum passes, more lawsuits are a certainty. Similar bans are being passed by cities in Colorado and Pennsylvania, and the State of New York has had a moratorium on fracking since 2008. All good news for lawyers specializing in inverse condemnation suits.

October 1, 2014

New UT Study on Water Use in Oil and Gas Production

A new study published by The University of Texas' Bureau of Economic Geology compares the amount of water used in producing oil from shale plays to the water used in producing oil from conventional reservoirs. The study concludes that water use for conventional and unconventional oil production is about the same. "Comparison of Water Use for Hydraulic Fracturing for Shale Oil and Gas Production versus Conventional Oil."

The study looked at water use in the Bakken and Eagle Ford plays. The ratio of water used to oil produced ranged from 0.2 to 0.4 gallons of water for each gallon of oil produced over the lifetime of a well in both plays - or 0.03 to 0.06 gallons of water per million British thermal units of energy from the oil produced. In comparison, U.S. conventional production uses from 0.1 to 5 gallons of water for each gallon of oil produced.

The study's conclusion: "the U.S. is using more water because HF [hydraulic fracturing] has expanded oil production, not because HF is using more water per unit of oil production."

According to the study, the amount of water used per mmBtu produced in the Bakken is substantially less than in the Eagle Ford: water use per well in the Bakken is about half that in the Eagle Ford, and about one-third per mmBtu of energy produced.

September 29, 2014

Texas' New Seismologist

Michael Brick has written an excellent article in the Houston Chronicle about the Texas Railroad Commission's new seismologist, David Craig Pearson. The article, "Vexed by Earthquakes, Texas Calls In a Scientist," relates the events leading up to his hiring, his background, and the RRC's initial foray into addressing the issue by proposing new rules on injection well operators.

Dr. Pearson grew up in McCamey, worked in the oil fields, studied at SMU, and worked at Los Alamos National Laboratory in New Mexico for 13 years. He left in 2006, returning to West Texas and ranching. He inherited some mineral rights in Upton County. When the RRC advertised for a seismologist, he applied and was hired.

So far, Dr. Pearson has published no conclusions, but the RRC has been praised for its new proposed rules. Pearson testified in August before the House Energy Resources Subcommittee on Seismic Activity that he wants to wait for reports from SMU's study of seismic and injection activity around the town of Azle, in the Barnett Shale, before drawing any conclusions. 

September 23, 2014

EPA Praises RRC

In a letter to the Texas Railroad Commission commenting on the RRC's proposed rules on curbing earthquakes caused by high-pressure injection of waste fluids, the Environmental Protection Agency "applauded the RRC's efforts to ensure it has sufficient regulatory authority to respond to any event of the type where concerns may arise." Maybe the agencies will kiss and make up? Not likely. But the EPA agrees with proposed rules published by the RRC that would require applicants for disposal well permits to submit information about the area's risk for earthquakes as part of their application. The rules also strengthen the RRC's authority to limit or halt injection from existing wells where earthquake events occur.

Initially the RRC was slow to respond to complaints about earthquakes. At one point, citizens from the town of Azle, particularly affected by earthquakes, staged a protest before the RRC at which Azle citizens serenaded the commission with their own composition based on Elvis Presley's All Shook Up.  The RRC has now hired its own seismologist, and although Commissioners are cautious about connecting earthquakes to oil and gas activity, the proposed rules are a step in the right direction.

Texas now has more than 3,600 active commercial injection wells; it granted 668 permits last year alone. Earthquakes strong enough to damage homes have occurred in the Barnett Shale region. Similar problems have occurred in Oklahoma and other regions. 

The proposed rule can be found here.  Other comments on the proposed rule can be found here. Texas Tribune article on the proposed rules is here. SMU is conducting a study of the quakes around Azle and has installed seismic stations in the area to monitor seismic activity.

September 16, 2014

Gas Contamination of Groundwater Traced to Faulty Casing

A study published in the Proceedings of the National Academy of Sciences, examining eight clusters of contaminated water wells in Pennsylvania and Texas, found that the wells' contamination was either from naturally occurring gas deposits -- i.e., the gas is naturally occurring within the aquifer -- or from poor casing and cementing of nearby gas wells. The study concluded that the hydraulic fracturing of the wells was not a cause of groundwater contamination. The study was led by a researcher at The Ohio State University and included researchers at Duke, Harvard, Dartmouth and the University of Rochester. The researchers were able to "fingerprint" the gas by measuring the amount of "noble" gases such as helium included with the natural gas. The researchers were able to distinguish between the fingerprints of naturally occurring methane in the aquifers and gas from the Barnett and Marcellus Shale formations. Ohio State's press release about the study can be viewed here.

I have written previously about the ongoing battle between Range Resources and the Lipskys over the Lipskys' claims that Range's wells contaminated their groundwater. A facet of that battle is pending in the Texas Supreme Court. This new study will add fire to the debate.