Articles Posted in Oil and Gas Law

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On May 12, 2016, the United States Environmental Protection Agency (EPA) issued its final Methane Rule,  mandating new limits on methane gas emissions, volatile organic compounds (VOCs) emissions and other by-products such as benzene associated with oil and natural gas production wells and storage tanks. The new EPA rule is meant to apply to new as well as existing, reconstructed and modified oil and gas wells and even those wells producing fewer than 12 b/d of oil. Methane is a major component of natural gas. The stated goal of the new rule is to reduce methane and other toxic gas emissions by 40% to 45% of 2012 levels by the year 2025.

Unfortunately, but not unexpectedly, the EPA’s Methane Rule is a one-size fits all scheme that is meant to be adopted across the board by oil and gas producers in all states. When the EPA announced its final rule on this matter, many groups were openly and adamantly critical of the new rule. Many in the oil and natural gas industry voiced concern about the financial stress that the new rule would put on producers. For instance, the rule is especially burdensome for stripper and marginal well operators, and given the low price of oil and gas these days, there are many more marginal well operators these days.

Fifteen States Object to the EPA’s New Rule And File A Lawsuit

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In 1994 Roland Oil Co. acquired the North Charlotte Field Unit Lease in Atascosa County, Texas. The Lease contained 31 wells, with the oldest wells drilled sometime in the 1950s. The Lease contained both active and inactive wells. Rule 14 of the Texas Railroad Commission requires that “dry or inactive wells” be plugged within one year of the termination of drilling operations. Delinquent inactive wells are required to be plugged “immediately unless the well is restored to active operation.” Rule 14 also requires structural testing of inactive wells that are more than twenty five years old prior to plugging and abandonment operations. If an operator fails to meet these requirements, the Railroad Commission can prohibit an operator from producing from any wells under the lease.

In 2005, Roland requested an extension of time to complete the required testing on some of the inactive wells on the Lease. The Railroad Commission determined that Roland had been delinquent on the required testing since 1994, denied the request, and also issued an order barring Roland from producing from any well on the Lease. Roland halted production from May 2005 to August 2006 to conduct repairs and to complete the testing required by the Railroad Commission. The Railroad Commission lifted the order barring production in August 2006.

Meanwhile, in June 2006, a mineral owner under the Lease notified the Railroad Commission that the lease had terminated for lack of production. In response, Roland claimed the Lease had not terminated for two reasons: First, the Lease contained a provision stating that the term of the Lease is “for the time that oil and gas are produced in paying quantities and as long thereafter as Unit Operations are conducted without a cessation of more than ninety consecutive days.” Roland argued that repairs and testing activities during the period of non-production met the definition of Unit Operations under the Lease. Secondly, Roland argued that the Railroad Commission order preventing production constituted “force majeure” which kept the Unit Lease alive despite lack of production.

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In an earlier blog post, we discussed the Texas fracing case that was headed to the Texas Supreme Court for further review. On April 24, 2015, the Texas Supreme Court issued its opinion in In Re Steven Lipsky, and determined that the Texas Citizens Participation Act does not require that courts apply a heightened standard of proof to claims requiring clear and specific evidence.


The Lipskys claimed they could set their drinking water on fire due to the nearby fracing activities of Range Resources. The Lipskys filed suit against Range for contamination of their water well and Range filed a counter-suit against the Lipskys and another party, Alisa Rich, alleging defamation, business disparagement, and civil conspiracy. The Lipskys and Rich filed a special motion under the Texas Citizens Participation Act to dismiss Range’s counter-suit.

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The Texas Supreme Court recently granted a petition for review in the case of Denbury Green Pipeline-Texas LLC v. Texas Rice Land Partners. The review will focus on how the courts are to apply a test created by the Texas Supreme Court concerning when an entity may identify itself as a common carrier. Common carrier status is critical because it allows a pipeline company to use eminent domain power (i.e., condemnation) to acquire pipeline easements.

When Is A Pipeline a Common Carrier Line?

Texas Rice Land Partners owned a rice farm and cattle ranch in Jefferson County on the Texas Gulf coast and refused to let Denbury Green Pipeline-Texas LLC (“Denbury”) survey the property for a carbon dioxide pipeline in 2008. Relying on Texas law at the time, Denbury began eminent  domain proceedings so they could conduct the survey. Denbury had indicated that it was a “common carrier” on the Texas Railroad Commission’s T-4 form for pipeline permits. The Texas Railroad Commission does not examine or evaluate this designation, but takes it at face value. In fact, the filing of a T-4 with the Railroad Commission is not really a permitting process at all, but simply a registration of the pipeline for information purposes. The trial court held that Denbury was a common carrier and enjoined Texas Rice Land Partners from interfering with Denbury’s surveying activities on the land. The Texas Ninth District Court of Appeals opinion affirmed the decision of the trial court based on the probability that the pipeline would serve third parties at some point after construction by transporting gas for customers who will either retain ownership of their gas, or sell it to unaffiliated parties. The Texas Supreme Court issued an opinion in 2012 announced the “Texas Rice test”: “for a person intending to build a CO2 pipeline to qualify as a common carrier under the Texas Natural Resources Code, a reasonable probability (which the Court indicated in a footnote means more likely than not) must exist that the pipeline will at some point after construction serve the public by transporting gas for one or more customers who will either retain ownership of their gas or sell it to third parties other than the pipeline company”. The Texas Supreme Court remanded the case to the trial court for application of the facts to the new “Texas Rice test”.

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Up until recently, to the frustration of the IRS, the cost basis for mineral interests and other assets for estate tax purposes did not have to be the same as the basis used for income tax purposes. In other words, the executor of an estate could use a lower value for the estate’s mineral interests in order to minimize the estate tax on those assets. Later, if a beneficiary of the estate sold those assets, the beneficiary could use a higher basis in order to minimize capital gain taxes. The value used by the executor created a presumption of the basis for income tax purposes, but the beneficiary selling that asset had the option to use a higher basis, so long as they could good provide the IRS with “clear and convincing evidence” that the value was actually higher.

Recently, the U.S. Congress enacted the Surface Transportation and Veterans Health Care Choice Improvement Act of 2015, which was signed into law July 31, 2015 and was effective immediately. One portion of this new law limits the beneficiary’s basis to the value used for estate tax purposes. In addition, executors of estates are now required to file information statements with the IRS regarding the basis used and also must provide beneficiaries information about the basis of assets they receive. This new reporting requirement applies to all estate tax returns filed after July 31, 2015 that were required to be filed but it does not apply to optional estate tax returns.

When the assets of the estate include mineral interests or royalty interests, it is important to obtain an accurate opinion of their value. If you are the executor of an estate and need valuation of the estate’s Texas mineral interests, please give our office a call. We will be glad to talk to you about preparing a valuation for you.

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The Texas Supreme Court recently addressed how a bequest in a will of a double fractional oil and gas interest should be interpreted in Hysaw v. Bretton et al  in an opinion entered on January 29, 2016. A double fraction occurs when an instrument expresses a royalty interest as the product of two fractions, such as “1/4 of the usual 1/8 royalty”. The problem with using a double fraction in a deed or a will is that it is not often clear whether the instrument has created a fixed or “fractional royalty”, or a floating “fraction of” royalty in situations where the lease provides for a royalty different than 1/8. Back in the day, royalties were almost always 1/8. However, these days royalties are usually not 1/8: they can range from 10% to 30% or more. So the question becomes whether the testator or grantor meant for the beneficiary or grantee to get 1/4 times 1/8, i.e., 1/32, no matter what the actual royalty is or whether the term “the usual 1/8” was meant as a stand-in figure to represent whatever the actual royalty is. For even a moderately producing oil or gas well, this difference can represent a lot of money over the life of the well. The dispute in this case was between the children’s heirs, some claiming the will intended a fractional interest of 1/32 royalty and others claiming that the will intended a floating fraction of 1/3 of whatever the royalty was.

Ethel Hysaw executed a will in 1947, dividing her three tracts among her three children. The fee simple distribution was as follows:

● Inez received 600 acres from a 1065 acre tract,

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On January 14, 2015 the U.S. Environmental Protection Agency (“EPA”) announced that it will release a draft rule aimed at curbing emissions of methane. This new rule will directly target new oil and gas production sources and natural gas processing and transmission. The EPA wants to reduce current emissions of methane up to 45% of 2012 levels by 2015. The Texas Director of Americans for Prosperity found this so antagonistic to business interests that he wrote an open letter asking the Texas Legislature to restrain the EPA.

The rule stands to negatively affect Texas and the state’s businesses and consumers. Since Texas produces about a third of the country’s oil and one quarter of its natural gas, Texas is a huge emitter of methane, which is considered by the EPA to be another warming gas. Methane is sometimes leaked during the oil and gas drilling process. It is possible to fix the methane problem but it is estimated to cost billions of dollars. For instance, industries can replace all their compressor equipment. The industry could capture the methane and possibly sell it. The federal government thinks that that without any intervention, methane emissions from the oil and gas industry are projected to increase by 40 to 45%.

Industry groups, who are skeptical (with good reason) about global warming in general and EPA regulations in particular, have doubted the science claiming that humans are behind global warming. David Porter, Railroad Commissioner lamented that “(t)he EPA’s rules are part of the President’s war on fossil fuels” and believes the rule will hurt Texas’ economy. Indeed, this rule come at a time when oil and gas industries are already struggling. The price of West Texas crude fell by 60% in the past six months. In addition, it is not as if the industry isn’t and hasn’t been aggressive in curbing its own emissions. President of EDI Rich Rynn said “You’d be surprised at the number of (oil and gas) companies that are proactive.” In fact, the industry has already reduced emissions voluntarily, despite soaring production: industry emissions have decreased 12% since 2011.

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I tell all my Texas clients (and anyone else who will listen) never to sell their mineral interests. There are a number of reasons why:

1. About 99.9% of the companies who claim to buy mineral interests are scams. What often happens is that they send you a solicitation letter which makes an incredibly high monetary offer for your mineral interests. They ask you to sign a deed, which is either enclosed with the letter or that they send you if you contact them, and request that you send the signed deed back to them. Next they file the deed in the deed records. After the deed is filed in the county deed records, they contact you and say that they discovered certain ambiguous “problems” with your title to your minerals, or the market for mineral interests has changed, or some other nonsense. They then tell you they will pay you, not what they offered in the letter, but a tiny fraction of what they offered. If you don’t take it, you are stuck with the deed filed in the deed records that shows you sold your mineral interest to them. In many cases, I’ve had to sue the company on a client’s behalf to force the company to cancel the deed. Even if the company cannot be found or has gone out of business, you will still probably have to file a lawsuit to get a court order cancelling the filed deed. Given the expense of litigation, this can be a huge burden.

One way to tell if a company is a legitimate concern or not is to tell them that you might be interested in selling your minerals but your requirements are: 1) they need to send you a written contract of sale with a specific price and an earnest money deposit which, if acceptable to you, you will sign and take with the earnest money to a title company; 2) the deed will be prepared by your attorney; 3) the transaction will be closed in a title company; and 4) they will be required to deposit the balance of the purchase price in good funds with the title company before they receive the deed. Most of these companies will tell you that is an unnecessary expense, or “they don’t do it that way”. This is a huge red flag. However, in my experience, even some of the scam artists will agree to this, but once you have paid your attorney to draft the deed and it’s time for them to put the purchase price in escrow, they will disappear or pull out.

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On May 18, 2015, the Texas Governor Greg Abbott signed HB 40 into law. The law is effective September 1, 2015. This new law effectively prohibits local city and county governments and subdivisions from regulating surface oil and gas activity in their jurisdictions. The law provides that all such regulation is now preempted by the state of Texas. The new law does have an exception, but it is so narrow as to be effectively useless.

This is not a good day for Texas property owners.  I foresee the law of unintended consequences coming into play here. Specifically, as oil and gas activities encroach on residential areas, the market value of those properties will decline, and may decline substantially. That means appraisal districts will have to reappraise these properties at a lower level. That in turn results in lower tax revenues. Texas counties are already pinched financially. Will Texas counties simply increase the tax rate to make up for the lost revenues? Texas property owners already bear huge tax burdens from county and school taxes. Many counties spent like drunken sailors when taxes were buoyed by taxation of oil and gas production during times of high oil and gas prices. Now they have huge overhead and new programs that they cannot pay for. What happens next will depend on how much oil and gas activity occurs in residential areas where it was previously prohibited and what impact that has on local taxes. To be announced.

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As of November 4, 2014 Denton, Texas was the first Texas city to ban fracing inside city limits with a ballot initiative that passed with almost 59 percent of the vote. The next day, the state’s energy lobby, Texas Oil and Gas Association, filed an injunction in response. The Texas General Land Office also separately filed suit to prevent Denton from enacting the ordinance. Arguments in both suits were based on the fact that well completion techniques, which include fracing and disposal, are preempted by the state regulation and that the ban cannot be enforced by a city. Opponents of the ban have also argued that the ban constitutes an unlawful taking of mineral rights. It is unclear if the courts would find the fracing ban to be an unconstitutional taking of property in violation of the Texas Constitution because it is not a ban on gas well drilling, only a ban on one type of gas recovery technique used during production.  More recently, the Texas legislature has prepared legislation that would actually ban all local regulation of oil and gas drilling, and not just fracing.

Implied Preemption in Texas

In Texas there is no doctrine of implied preemption under state law. This means that in order for a city or municipal regulation to be preempted by state law the Texas State Legislature must “with unmistakable clarity” dictate that state law controls. In January 2014, the state of Texas adopted new rules in the Texas Administrative Code relating to hydraulic fracturing in Texas. The new rules do not specifically preempt municipalities from adopting additional regulations.