Articles Posted in Oil and Gas Law

A case that has gained attention in the Texas oil and gas industry is the case of Samson Exploration v. T.S. Reed Properties which is currently awaiting a decision by the Texas Supreme Court. The case involves three gas wells and two mistakenly overlapping pooling units in Hardin County, Texas.  The boundaries of the first unit were amended by the well operator, but the boundaries of the second unit were not. The two main issues, as stated by the Texas Ninth Court of Appeals, are : “First, whether the stakeholders participating in (the first unit) can recover damages from the operator of the unit when the operator amended the boundaries of the unit to exclude a well that was within the boundaries of the original unit, and where the stakeholders accepted royalties attributable to the amended unit without challenging the operator’s authority to amend the original unit’s boundaries. Second, whether the stakeholders in (the second unit), based on their claims for breach of contract, can recover damages from the operator due to the operator’s failure to pay royalties on oil and gas produced from a well that the operator contends was (originally)  included in that unit by mistake”.

In October 2015, the Texas Ninth Court of Appeals opinion ruled that the stakeholders in the first unit had ratified the amendment to the unit by accepting royalties attributable to the amended first unit. Therefore, those stakeholders should recover nothing. The Ninth Circuit further determined that the stakeholders in the second unit could recover damages from the well operator for the operator’s failure to file an amendment to the description defining the pooling unit’s boundaries, but that the award of damages in the trial court was excessive because it awarded royalties for prior to the time the unit existed.

Many in the Texas oil and gas industry, like Texas Alliance of Energy Producers, support Samson’s claim that the royalty owners in the first gas unit ratified the unit amendment by accepting royalties after the unit was amended, and that they should not be required to pay royalties from one well to lessors in both gas units.

The case of Rippy Interests LLC. v. Nash, LLC is interesting because it examines what type of operations will keep a Texas oil and gas lease in force after the primary term has expired, and also what constitutes a repudiation of an oil and gas lease in Texas.

On January 18, 2006 Range Production I, L.P. acquired a mineral lease (hereinafter the “Range Lease”) on acreage in Leon County owned by Nash LLC. The primary term of the lease was for three years, with an option to extend the lease for an additional two years. Range exercised the option and extended the term of the Range Lease to January 18, 2011. In the fall of 2009, Range assigned its lease to Rippy Interest LLC. A year later, Rippy received a drilling permit to drill a well on the Range Lease.

The same month that Rippy received the drilling permit, Nash LLC granted a top lease for the acreage to KingKing, LLC (hereinafter the “KingKing Lease”), which was expressly subordinate to the Range Lease and would only take effect upon the expiration of the Range Lease. The Range Lease contained the following two clauses, which are fairly standard clauses (in one form or another) in Texas oil and gas leases:

The United States Court of Appeals for the Fifth Circuit issued an unpublished opinion last year in Waggoner v. Denbury Onshore, LLC, et al. concerning the application of state antitrust law to  royalty payments. It should be noted that while the opinion is instructive on how the 5th Circuit Court of Appeals views the issues discussed, the opinion is explicitly not intended as precedent, except under the limited circumstances set forth in the Fifth Circuit Rule 47.5.4.

Background of the Case:

In 1984, James Waggoner acquired an oil, gas, and mineral lease for a section of a carbon dioxide (CO2) formation in Rankin County, Mississippi. Subsequently, Shell Western E&P Inc., a subsidiary of Royal Dutch Shell Inc., petitioned the Mississippi State Oil and Gas Board for authority to pool the interests in a large section of land, which included Waggoner’s interest. Waggoner entered an agreement with Shell to place 77 acres of his land into the pooled tract of land in exchange for a 6.25% overriding royalty interest in the well until payout with an option to convert the overriding royalty interest into a 40% working interest at a later date. Waggoner and Shell  also entered into an Operating Agreement that dictated that the price of CO2 (upon which royalties were to be calculated) would be the “volume weighted average price”. After the well paid out, Waggoner converted the overriding royalty interest into a working interest, which allowed Waggoner to take either a proportional share of the CO2, or a proportional share of the volume weighted average price of the CO2 that Shell received.

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

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.

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.

Background

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.

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”.

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.