The Dusky Gopher Frog Causes Big Problems for Industrial and Commercial Development in Parts of St. Tammany Parish

In 2010, under the Endangered Species Act (“ESA”), the United States Fish and Wildlife Service (“the FWS”) designated 6,477 acres in Mississippi and Louisiana as “critical habitat” for the Rana sevosa or the dusky gopher frog.  This frog has historically lived in nine counties or parishes across Louisiana, Mississippi, and Alabama.  Since its 2001 designation as an endangered species, an estimate of 100 adult frogs are known to only exist in Harrison County, Mississippi.  The gopher frog spends most of its time living underground, but will migrate to short-lived, ephemeral ponds to breed.  After breeding, the frog will return to its underground habitat, along with its offspring.  According to the FWS, the greatest threat to the gopher frog population is the low number of adult frogs and human-induced environmental stressors, such commercial development.  Markle Interests, L.L.C. v. United States Fish & Wildlife Serv., 2016 WL 3568093, at *1-2 (5th Cir. June 30, 2016).

Furthermore, in an attempt to return the gopher frog population to Louisiana, the 2010 designation by the FWS included 1,544 acres of private land in St. Tammany Parish (“Unit 1”).  A group of private landowners (“the Landowners”), who owned all of Unit 1, brought a lawsuit in 2013 for declaratory judgment and injunctive relief against the FWS, its director, the United States Department of the Interior, and the Secretary of the Interior.  The Landowners claimed that their property value decreased due to the designation and that they had future plans to develop Unit 1 for residential and commercial development and timber operations.  However, these plans could not go forward due to the FWS’s designation of Unit 1 as a critical habitat.  Id.

On August 22, 2014, District Judge Martin L.C. Feldman of the United States District Court for the Eastern District of Louisiana granted the FWS’s Motion for Summary Judgment and held that the FWS properly applied the Endangered Species Act to private lands in St. Tammany Parish.  Subsequently, on June 30, 2016, in a 2-1 decision, the United States Court of Appeals for the Fifth Circuit affirmed Judge Feldman’s ruling, upholding the FWS’s designation of Unit 1 as a “critical habitat” under the ESA.  Id.

Writing for the Fifth Circuit, Circuit Judge Stephen A. Higginson first ruled that the Landowners had standing to bring a lawsuit against the FWS under Article III of the United States Constitution.  The Court held that the Landowners’ assertion of lost property value is a “concrete and particularized injury that supports standing.”  Id. at *4; U.S.C.A. Const. Art 3, § 2, cl 1.  Next, the Court rejected the Landowners’ four challenges to the FWS’s designation of Unit 1 as a critical habitat for the dusky gopher frog:

  • First, the Court rejected the Landowners’ argument that the FWS’s designation violated the ESA. The FWS brought forth sufficient evidence to prove that designating occupied habitat in Harrison County, Mississippi alone was inadequate to ensure the conservation of the gopher frog and Unit 1 was essential for the conservation of the frog due to its landscape and natural, ephemeral ponds.  Thus, the Court ruled that the designation of Unit 1 as a critical habitat was not arbitrary and capricious, and it did not violate the ESA.  Markle Interests, 2016 WL 3568093, at *10-12.
  • Second, the Court addressed the issue of the FWS’s refusal to exclude Unit 1 from the critical habitat designation. The ESA mandates that the FWS “take into consideration the economic impact…of specifying any particular area as critical habitat.”  16 U.S.C. § 1534(a).  After this is done, the FWS may exclude any area from the critical habitat if it “determines that the benefits of such exclusion outweigh the benefits of specifying such areas as part of the critical habitat.” Id. at *12-13.  Here, the Landowners argued that Unit 1 has a potential loss of $33.9 million in commercial development over a period of twenty years, and that the benefits of excluding Unit 1 “clearly outweigh the benefits of including it in the designation.”  Id. at *12.  However, the Court stated that after the FWS fulfilled its statutory obligation to consider the economic impacts, a decision to not exclude an area is discretionary.  Under the Administrative Procedure Act (“APA”), such decisions “committed to agency discretion by law” are not reviewable in federal court under the APA.  Id. at *13.
  • Third, the Court held that the ESA did not exceed Congress’s powers to regulate commerce under the Commerce Clause. The Court held that the designation of Unit 1 as a critical habitat is an intrastate activity and an essential part of a larger regulation of economic activity.  This regulatory scheme could be undercut unless the intrastate activity is regulated. Id. at *14.
  • Lastly, the Court rejected the Landowners’ claim that the FWS violated the National Environmental Policy Act by failing to prepare an environmental impact statement before designating Unit 1 as a critical habitat. The Court held that the FWS did not need a NEPA impact statement because the designation did not effect changes to the Landowners’ physical environment.  “The ESA statutory scheme makes clear that [the FWS] has no authority to force private landowners to maintain or improve the habitat existing on their land.” Id. at *18.

Therefore, after rejecting all of the Landowners’ arguments, the Fifth Circuit ruled in favor of the U.S. Fish and Wildlife Service and held that the Landowners’ privately owned land can be designated as a critical habitat for the dusky gopher frog.  This opinion suggests that the federal government, through the FWS, may prevent the industrial and commercial development of a private citizen’s land, even though the endangered species does not presently occupy the critical habitat.

A copy of the Fifth Circuit’s opinion can be found here.

For further information, contact Collin Melancon at cmelancon@liskow.com or James Lapeze at jelapeze@liskow.com.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

Louisiana Department of Revenue Targets Energy Companies in Rash of Oil Severance Tax Audits

The oil and gas industry has a significant and far reaching economic impact in Louisiana. According to one 2014 study, the total direct and indirect impact on the state is approximately $73.8 billion.[1] Taxes make up a large part of the industry’s direct economic impact in Louisiana: In 2013, the industry paid nearly $1.5 billion in taxes to the State, about 14.6% of the total taxes, licenses and fees collected that year.[2] A large chunk of the taxes paid by oil and gas companies are severance taxes, which are levied on the production of natural resources taken from private and public land or water bottoms within the territorial boundaries of the state.[3] Natural resources might include, for example timber, minerals like oil and gas, coal, salt, or sulphur. Overall, collections on oil and gas amount to nearly 92% of all severance tax collections in the state.[4]

In the last few months, the Louisiana Department of Revenue (the “Department”) has audited dozens of Louisiana oil producers seeking additional oil severance taxes. As explained below, the Department has issued audit findings which determine that any negative adjustments embedded into the negotiated prices in various oil purchase contracts were not allowable. As a result, the Department is seeking payment of severance taxes on a price which is higher than the one actually paid pursuant to the contracts. This new interpretation has resulted in significant liability for many producers, some in the hundreds of thousands of dollars.

Severance taxes on oil are paid based on the value of the oil at the time and place of severance. La. R.S. 47:633(7)(a). The value of the oil is the higher of: (1) The gross receipts received from the first purchaser, less charges for trucking, barging and pipeline fees, or (2) the posted field price. Id. Since posted field prices are uncommon today (and the industry would assert that the concept no longer exists and should be removed from the law), the amount of severance taxes due to be paid is likely based on option (1) above. If neither the first purchaser nor producer of the oil claims a deduction for trucking, barging or pipeline fees, then the value of the oil for tax purposes is based solely on the gross receipts received from the first purchaser. Normally, the calculation process ends here and the taxpayer submits payment accordingly. The recent audits by the Department, however, indicate a new state of affairs.

The oil purchase agreements recently targeted by the Department include a price formula which begins with a “market center price” (i.e. West Texas Intermediate Crude Cushing OK), and then includes various positive and negative adjustments to that market center price to arrive at the price to be paid for the crude oil. For instance, if the oil is purchased at or near the lease, the particular lease may include a deduction or premium applicable only to that lease. This increase or decrease from the market center price might be based on a variety of factors. In its recent audit reports, the Department has “unbundled” the contractually negotiated prices actually paid, and seeks to assess additional severance taxes based upon a hypothetical amount of additional value which ignores any negative adjustments embedded in the price formula. The Department essentially created its own theoretical prices for the oil, and is attempting to assess an additional severance tax based on that amount.

Consider the following hypothetical:

  • Operator X enters into an Oil Purchase Agreement to sell oil from a mineral lease to First Purchaser Y. Under the terms of the Agreement, First Purchaser takes title to the oil at or near the lease. By law, Operator X is the “severer” of oil and is therefore subject to the Louisiana oil severance tax under LA. R.S. 47:633(7); but, First Purchaser Y agrees to withhold the severance taxes from the proceeds due to Operator X and reports and remits these taxes to the Department.
  • Pursuant to the Oil Purchase Agreement, Operator X and First Purchaser Y agree to a price formula which begins with a market center price of $65, and then deducts $3 for a final price of $62 per barrel. Accordingly, First Purchaser Y withholds severance taxes based upon the $62 price it paid to Operator X, and reports and remits the same to the Department.
  • A year or two after the sale, Operator X receives an audit report from the Department which provides that Operator X owes additional severance taxes for those months it sold oil to First Purchaser Y under the Oil Purchase Agreement. The audit letter from the Department indicates that the value of the oil for severance tax purposes was actually $65 per barrel, and not the $62 negotiated price. Therefore, the Department proposes to assess an additional severance on the extra $3 per barrel, plus interest and penalties.

A taxpayer who has been audited and receives a notice of proposed tax due from the Department must act quickly to protect its procedural rights. For any significant proposed assessment, a taxpayer should always seriously consider how it can protect itself from additional tax liability.

If you have any questions about this or any other tax issues, please contact RJ Marse at rjmarse@liskow.com, Jim Exnicios at jexnicios@liskow.com, or Cheryl Kornick at cmkornick@liskow.com.

[1] http://www.lmoga.com/issues-initiatives/economic-impact/

[2] http://www.lmoga.com/issues-initiatives/economic-impact/

[3] http://dnr.louisiana.gov/assets/TAD/data/severance/la_severance_tax_rates.pdf 

[4] http://dnr.louisiana.gov/assets/TAD/data/severance/la_severance_tax_rates.pdf

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

Navigating Non-Compete and Other Key Talent Issues: A Primer for Employers

Finding new customers and growing sales and market share are the Holy Grail.  One way to achieve these objectives is to hire talented sales professionals or managers from competitors.  These individuals already know the market and have relationships with potential new customers.

But these individuals’ employers have invested time and money in training them and provided them with trade secrets and confidential business information.  They will fight, in the marketplace and the courts, when a competitor poaches their key team members.

Your business could find itself on either side of this equation and must prepare in advance for acquiring employees from, and losing employees to, a competitor.  Here are a few tips to help protect your business from the risks of expensive litigation associated with hiring a competitor’s employee, or the loss of critical business assets when your employee departs for a job with a competitor.

When Hiring a Competitor’s Employee

  • Require the prospective employee to provide you with all non-compete, confidentiality or restrictive covenant agreements with current or former employers, and to certify in writing that he has done so. Keep in mind that if the agreements state that they are confidential, the employee may need to provide them to your counsel.
  • Have your counsel analyze the non-compete, confidentiality or restrictive covenant agreements and advise you as to their enforceability and scope. Louisiana’s non-compete statute is unique and may invalidate common provisions in agreements drafted in other states.
  • Consider encouraging the employee to file a declaratory judgment action to invalidate all or part of restrictive covenants that are defective.
  • Consider whether you will indemnify the employee if a former employer files suit against him.
  • Advise the employee in writing that you do not want any trade secrets or confidential business information from other employers. Require a written commitment that the employee understands this directive and will not bring confidential documents into your workplace or download them into your information systems.
  • Reiterate these directives when the employee comes on board. And consider monitoring the employee’s email accounts and computer/phone after the move to ensure compliance with these directives.
  • Notify managers that they must refrain from asking the employee to disclose former employers’ trade secrets and confidential business information in an effort to gain a competitive advantage. Advise managers of the risks they and your company face under trade secrets and unfair business practices laws, including the new federal Defend Trade Secrets Act.

Protecting Trade Secrets and Confidential Business Information if a Key Employee Leaves to Work for a Competitor

  • Carefully identify the information and documents that constitute your business’s trade secrets and are truly confidential.
  • Protect trade secrets and confidential business information by: (i) restricting access to sensitive documents, files and emails to those with a need to know; (ii) using password protection and other security measures with sensitive documents; and (iii) installing security measures on employee phones and devices (particularly if you have a BYOD policy) so that information can be removed when the employee departs or loses the device.
  • Draft confidentiality and document retention policies and require employees to sign acknowledgments of these policies.
  • Draft Confidentiality/Non-Disclosure Agreements and require employees to sign them.
  • Require key employees to sign non-competition and non-solicitation agreements that comply with the law of the jurisdiction where they are employed. Be mindful of the unique requirements of the Louisiana non-compete statute.
  • Remind any departing employee of confidentiality and non-disclosure obligations during exit interviews and by written directives at the time of, or immediately after departure. Make written demands that the employee preserve all evidence related to employment with your company, his departure/move, and employment with the competitor.
  • Circle the wagons immediately upon the employee’s departure and contact key customers to preserve your company’s relationship with them.
  • Monitor the departed employee’s subsequent employment for connections to a competitor.
  • Consider notifying the departed employee’s new employer of the employee’s confidentiality and non-disclosure obligations. Consult with counsel before doing so.
  • Hire an outside technology consultant and conduct forensic examinations of the departed employee’s computer, phone and other devices to determine whether trade secrets or confidential information were stolen and, if so, to develop evidence for litigation purposes.
  • If necessary, file suit to obtain an injunction or otherwise enforce restrictive covenants and protect trade secrets and confidential information.
  • Ensure that other key personnel are content so you do not have more departures.

For more information, please contact Thomas J. McGoey II at tjmcgoey@liskow.com or Kindall C. James at kjames@liskow.com or go to www.liskow.com.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

EPA Biting Off More Than It Can Chew? Agency Publishes First Year Implementation Plan for New TSCA Legislation

This is Part II of our TSCA update following the recent changes to the TSCA legislation.

On June 29, 2016, the U.S. Environmental Protection Agency (“EPA”) released its first year implementation plan for the recently-enacted amendments to the Toxic Substances Control Act (“TSCA”).  Faced with the ambitious requirements and timeframes laid out by the Frank R. Lautenberg Chemical Safety for the 21st Century Act (the “Act”), EPA has planned out its implementation activities during the first year. The agency divided up actions into four categories: Immediate Actions, Framework Actions, Early Mandatory Actions, and Later Mandatory Actions (beyond the first year of implementation).

Immediate Actions

From Day 1, EPA has to make an affirmative determination of safety before the manufacture of new chemicals (or significant new uses of chemicals) can commence.  For notices received prior to enactment, EPA’s goal is to complete the review within the remaining time under the original deadline, but in any event no later than 90 days from enactment.  The first 30 days will see a number of actions related to the Confidential Business Information (“CBI”) process.  Specifically, EPA will create a plan for linking confidential business information to a unique identifier, develop an approach for routine review of confidentiality claims, and provide additional information on statements and certifications required for CBI claims.  Within the next six months, EPA will issue risk management rules for three solvents: Trichloroethylene or TCE, Methylene Chloride, and N-Methylpyrrolidone or NMP.

Framework Actions

A number of proposed rules expected in the next six months will provide the framework for new regulatory processes required by the Act, including prioritization of chemicals for risk evaluation, evaluation of the risk of high priority chemicals, fee collection, and inventory reporting.  In the next six months, EPA also plans to issue the initial list of ten chemicals to undergo risk evaluations and create a new Science Advisory Committee on chemicals.

Early Mandatory Actions

EPA also expects to take action on a number of early mandatory requirements.  EPA will publish a list of mercury compounds prohibited from export by mid-September of this year.  Within the next six months, the agency will review the “small business” definition for purposes of TSCA and submit the first TSCA implementation report to Congress.  Finally, the plan for the first year of enactment also includes publishing the scope of evaluation for the first 10 chemicals, preparing the agency’s first annual plan for risk evaluation of chemicals, and publishing an inventory of mercury in commerce.

Beyond the first year of implementation, EPA will be required to issue additional rules on mercury reporting and CBI substantiation, as well as come up with a strategy for alternative testing methods.  There may be some doubt about whether EPA can meet all these aggressive implementation goals, but one thing is for sure: the regulated community can expect a lot of regulatory development in this area for the foreseeable future.

A copy of EPA’s First Year Implementation Plan can be found here.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

BOEM Releases Long Awaited New Financial Assurance Notice to Lessees and Operators

The Bureau of Ocean Energy Management (BOEM) released its long awaited new Notice to Lessees and Operators (NTL) updating the procedures and criteria used to determine when and if additional supplemental financial assurance is required for an Outer Continental Shelf (OCS) lease, pipeline right-of-way, or right-of-use and easement.  New BOEM NTL No. 2016-N01, dated July 12, 2016, takes effect on September 12, 2016 and supersedes and replaces NTL No. 2008-N07, which was commonly referred to by industry as the “supplemental bond” NTL.

While NTL No. 2016-N01 contains several changes in policy, one of most significant for the offshore oil and gas industry is the elimination of the all-or-nothing financial exemption from the requirement to provide supplemental financial assurance allowed under NTL No. 2008-N07.  Under new NTL No. 2016-N01, BOEM may allow a lessee or holder of a right-of-way or right-of-use and easement to self-insure up to 10% of that entity’s tangible net worth depending upon BOEM’s evaluation of that entity’s financial ability to carry out its obligations based on (1) financial capacity; (2) projected financial strength; (3) business stability; (4) reliability; and (5) record of compliance.  BOEM plans to hold workshops in Houston and New Orleans prior to the effective date of new NTL No. 2016-N01. A copy of NTL No. 2016-N01, the NTL implementation timeline, and information regarding the BOEM workshops can be found at the links below.

NTL No. 2016-N01
NTL Implementation Timeline
BOEM Workshops

Liskow & Lewis will host a seminar in September addressing how those in the offshore oil and gas industry can best position themselves to comply with the new requirements of BOEM NTL No. 2016-N01.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

Legislation Breathes New Life into the 40–Year Old TSCA Statute

This is Part I of a two-part series looking at the recent changes to the TSCA legislation. This article will explore the changes introduced by the Act. A follow-up article will explore the EPA’s recently released plan for implementing these changes.

On June 22, 2016, President Obama signed the Frank R. Lautenberg Chemical Safety for the 21st Century Act (the “Act”), which significantly amended the Toxic Substances Control Act (“TSCA”). See https://www.epa.gov/assessing-and-managing-chemicals-under-tsca/frank-r-lautenberg-chemical-safety-21st-century-act. As has been widely reported in the press, the Act significantly enhances TSCA and gives EPA additional authority to regulate chemicals in commerce.

Evaluation of Chemicals

For the first time, EPA must make an affirmative finding on the safety of a new chemical or significant new use of an existing chemical before the chemical (or new use) is allowed in the marketplace. EPA can impose restrictions as a condition for approval or prohibit the manufacture, processing, or distribution of the chemical altogether.

Existing chemicals will be prioritized (high priority and low priority) based on risk to human health or the environment, including to susceptible populations. This categorization cannot consider cost or other non-risk factors. High priority chemicals will then need to undergo a risk evaluation.  Low priority chemicals do not need to be evaluated unless the manufacturer requests it.

To determine if there is an unreasonable risk to human health (including to susceptible populations) or the environment, chemicals will be evaluated against a new risk-based safety standard.  This evaluation cannot consider cost or other non-risk factors. EPA can request testing as part of the prioritization or evaluation process without first having to demonstrate the presence of an unreasonable risk.

Addressing Unreasonable Risk

If unreasonable risks are identified, EPA must take a final risk management action (e.g., ban, phase-outs, or other restrictions).  In choosing what actions to take, EPA can consider cost and availability of alternatives, but the agency is no longer required to choose the least burdensome action.

Confidential Business Information

The Act makes it harder to obtain and keep protection for Confidential Business Information (CBI).  For example, claims of confidentiality must be substantiated and certified.  EPA is required to review all new requests for protection from disclosure of the specific chemical identity of a chemical substance, as well as at least 25% of all other requests for disclosure protection.  EPA also is required to review certain past claims to determine if CBI protection is still warranted.  CBI protection expires after 10 years, at which time the manufacturer must re-substantiate its claim.  CBI protection generally does not apply to chemicals for which the agency issues a ban or phase-out.

Other Changes

  • More stringent requirements and deadlines put in place for chemicals considered to be Persistent Bioaccumulative Toxics.
  • New reporting requirement for chemicals in commerce for the last 10 years so that EPA can classify chemicals in TSCA inventory as active or inactive.
  • Funding for implementation provided via new fees associated with reviews, notices, and evaluations.
  • Existing state requirements (prior to 4/22/16) are grandfathered.  State action allowed if EPA has not addressed the specific chemical, but preempted once EPA finds that the specific chemical is safe or takes final action to address risks.  States can ask for exemption to preemption.
  • The Act creates additional requirements for mercury export and disposal.
  • The Act increases the monetary amount of civil and criminal penalties.  The Act also adds criminal liability for knowing endangerment.

Many of these changes will require further rulemaking before they are fully implemented.  Therefore, the full impact on regulated entities will not be known until the agency proposes specific rules.  Part II of this series will explore EPA’s immediate plan for implementation of these changes.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

SAFE PIPES Act: 2016 Legislation Affecting PHMSA

President Obama signed the Protecting our Infrastructure of Pipelines and Enhancing Safety Act or the SAFE PIPES Act into law on June 22, 2016.  The Safe Pipes Act reauthorizes the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) through 2019 as well as its associated programs, including the one-call notification program, the pipeline integrity program, and state damage prevention programs.  (PHMSA’s authorization previously expired in 2015.)  Also, the SAFE PIPES Act authorizes several initiatives and studies to strengthen existing safety procedures and programs; invites States with a pipeline safety program certification, at their request, to participate in the inspection of interstate pipeline facilities; and requires the U.S. Department of Transportation to analyze the potential for leaks to occur at underground natural gas storage facilities in the United States, similar to the Aliso Canyon gas leak in southern California in 2016.  Importantly, the SAFE PIPES Act mandates the PHMSA provide a report to Congress within eighteen months studying the risks and safety recommendations for existing hazardous liquid pipelines.  PHMSA’s findings have the potential to increase inspection, monitoring, and repair requirements for liquid pipelines, especially for the United States’ aging pipeline infrastructure.

The full text of the SAFE PIPES Act can be found here.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

Texas Supreme Court Rules Oil and Gas Producer Not Entitled to Sales Tax “Manufacturing Exemption”

On June 17, 2016, the Texas Supreme Court ruled that an oil and gas producer (“Southwest”) was not entitled to a statutory exemption from sales taxes on its purchases of casing, tubing and pumps used in the production of oil and gas (the “Equipment”).

At issue in Southwest Royalties, Inc. v. Hegar was whether the Equipment qualifies under the so-called “manufacturing exemption” found in Section 111.104(a)(2) of the Texas Tax Code,  which exempts:

tangible personal property directly used or consumed in or during the actual manufacturing, processing, or fabrication of tangible personal property for ultimate sale if the use or consumption of the property is necessary or essential to the manufacturing, processing, or fabrication operation and directly makes or causes a chemical or physical change to:

(A) the product being manufactured, processed, or fabricated for ultimate sale; or

(B) any intermediate or preliminary product that will become an ingredient or component part of the product being manufactured, processed, or fabricated for ultimate sale[.]

Upon being denied a tax refund, Southwest sued the Comptroller and the Attorney General (the “State”), asserting that the Equipment qualified for the exemption because it is necessary or essential to the “processing” of hydrocarbons as they are extracted from the reservoir and brought to the surface.  Specifically, Southwest contended that it processed the hydrocarbons by creating pressure and temperature changes as it brought the minerals to the surface, which resulted in the hydrocarbons being converted from a liquid to a gaseous state and vice versa.  The State contended that bringing minerals to the surface does not constitute “manufacturing,” and put on evidence to show that the phase changes identified by Southwest were the result of natural changes in pressure in temperature and were not caused by Southwest’s equipment.  In other words, it was “undisputed that hydrocarbons undergo physical changes as they move from underground reservoirs to the surface; the disagreement [was] about the role [the Equipment] play[ed] in those changes.”

The trial court ruled for the State upon finding that, while physical changes do occur to hydrocarbons while they are extracted from the ground and lifted to the surface, those changes were directly caused by temperature and pressure changes as the hydrocarbons moved upward toward the surface, rather than by the Equipment, which was an indirect cause of, and merely incidental to, those physical changes.  Therefore, the Equipment did not qualify for the exemption.

The Texas Supreme Court rejected the State’s request for deference to the Comptroller’s interpretation of Section 111.104(a)(2), confirming that agency deference is appropriate only in the case of ambiguous statutes.  In finding the statute unambiguous, the Court sided with Southwest in holding that the term “‘processing’ includes matters outside the confines of ‘manufacturing,’” and is not merely “encompassed within ‘manufacturing,’” as the State argued.  Thus, the Court found the exemption applicable to non-manufacturing activities that otherwise meet the definition of “processing” or “fabrication.”  Nevertheless, the Court did adopt the Comptroller’s definition of “processing” as found in 34 Tex. Admin. Code § 3.300(a)(10):  “The physical application of the materials and labor necessary to modify or change the characteristics of tangible personal property.”

The Court ultimately found the exemption inapplicable to Southwest’s Equipment on the grounds that the Equipment did not “process” the hydrocarbons (i.e., did not “modify or change the characteristics” of the hydrocarbons).  In so ruling, the Court expressly noted that Southwest did “not challenge any of the trial court’s findings of fact” or “the evidence supporting those findings,” which showed that the phases changes resulted from pressure and temperature changes.  According to the Court, “[n]o evidence identified any way Southwest’s equipment acted upon the hydrocarbons to cause a modification or change other than by being the vehicle through which they exited the underground formation and traveled to the surface.”  Instead, “[t]he changes in the substances were caused not by the application of equipment and materials to them, but by the natural pressure changes that occurred as the hydrocarbons traveled from the reservoir through the casing and tubing to the surface.”  Thus, because the Equipment was not used to “process” or directly cause the changes to the hydrocarbons, Southwest was not entitled to the exemption.

Liskow & Lewis attorneys Butch Marseglia and Jillian Marullo submitted an amicus brief in Southwest Royalties on behalf of EOG Resources, Inc.

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

Tightening the Timeline for Original Condition: the First Circuit Denies Writ from Ruling Applying Subsequent Purchaser Doctrine to Dismiss Claims Against a Mineral Servitude Owner

In the watershed Corbello[1] decision, the Louisiana Supreme Court affirmed a $33 million award—the cost to restore property valued at $108,000 to its “original condition” after it was damaged by oil and gas operations.  If Corbello pressed the accelerator on “legacy” litigation, Eagle Pipe tapped the brakes.

The Louisiana Supreme Court’s decision in Eagle Pipe & Supply v. Amerada Hess Corp.[2]  held that a landowner does not have a claim for property damage that occurred before his ownership (absent an assignment or subrogation to that right from the seller).  As a practical consequence of Louisiana’s long oil heritage, many current landowners acquired their property long after oil and gas operations—and any attendant damages—first occurred.  Thus, the “subsequent purchaser doctrine” has become a key defense for mineral lessee defendants in legacy litigation. (For more information on how the subsequent purchaser doctrine has been applied in legacy cases, click here.)

Recently, the subsequent purchaser defense was applied to dismiss claims against a mineral servitude owner in Sterling Sugars, Inc., v. Amerada Hess Corporation, No. 100091, 17th JDC, Lafourche Parish. Article 22 of the Mineral Code states that a mineral servitude owner “is obligated, insofar as practicable, to restore the surface to its original condition at the earliest reasonable time.” The Sterling Sugars landowner, which acquired its property in 1998, argued that Article 22 obligated the mineral servitude owner to restore the property to its pre-operation condition.  Operations began in 1937; thus, the plaintiff’s claims would have required the servitude owner to repair alleged damage predating the landowner’s ownership by 60 years.

After the trial court applied the subsequent purchaser doctrine to dismiss the plaintiff’s claims for pre-1998 damage against the mineral lessee, the mineral servitude owner filed its own motion for partial summary judgment arguing that the subsequent purchaser doctrine likewise applied to the plaintiff’s mineral servitude claims.  The trial court accepted the argument, and ruled that “all claims against the [mineral servitude owner] for damage that occurred prior to plaintiff’s acquisition of the property at issue, including claims for monetary relief or restoration, are DISMISSED with prejudice.”[3]

The plaintiff sought writs from the First Circuit Court of Appeal. Yesterday, (June 13, 2016), the First Circuit denied the writ “on the showing made.” Sterling Sugars Inc., v. Amerada Hess, et al., 2015-CW-1857 (La. App. 1 Cir. 6/13/16). Thus, the writ denial supplies jurisprudential support that the subsequent purchaser defense applies to claims against mineral servitude owners, including claims for “original condition” restoration under Mineral Code article 22.  As applied in Sterling Sugars, the subsequent purchaser doctrine sets the condition to which a mineral servitude owner must restore encumbered property to the condition which existed when the current landowner purchased the property.

[1]           Corbello v. Iowa Prod., 2002-0826 (La. 2/25/03); 850 So.2d 686.

[2]           10-2267 (La. 10/25/11); 79 So. 3d 246.

[3]           Sterling Sugars Inc., v. Amerada Hess Corporation, No. 100091, 17th JDC (Judgment on PXP Gulf Coast LLC and PXP Louisiana LLC’s Motion for Summary Judgment Based on the Subsequent Purchaser Doctrine (November 25, 2015)).

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

Amendment to Louisiana’s Risk Fee Statute That Allows For Notices After Spudding Is Awaiting Governor’s Signature

Effective August 1, 2016, unless vetoed by the Governor, the Louisiana Legislature will have amended the Risk Fee Statute, La. Rev. Stat. Ann. § 30:10, which governs unit operations in the absence of a joint operating agreement.  The amendment is contained in Senate Bill No. 388, and would make the changes summarized below.

  1. Notices Allowed After Spudding

Under prior law, any owner drilling or intending to drill a well serving the unit was required to notify all other owners in the unit “prior to the actual spudding of any such well of the drilling or the intent to drill and give each owner an opportunity to elect to participate in the risk and expense of such well.”

The amendment strikes the language underlined above and adds language referencing wells already drilled, resulting in the following:

“Any owner drilling, intending to drill, or who has drilled a unit well, a substitute unit well, an alternate unit well, or a cross-unit well on any drilling unit heretofore or hereafter created by the commissioner, may, by registered mail, return receipt requested, or other form of guaranteed delivery and notification method, not including electronic communication or mail, notify all other owners in the unit of the drilling or the intent to drill and give each owner an opportunity to elect to participate in the risk and expense of such well.”

  1. Estimated or Actual Drilling Costs Due Within Sixty Days of Spudding or Receipt of the Notice, Whichever is Later

Because prior law required notice prior to spudding, the due date for payment of drilling costs determined by the AFE sent with the notice was within sixty (60) days of spudding.

The amendment provides that estimated or actual drilling costs determined by the AFE sent with the notice are due within sixty (60) days of the actual spudding of the well or receipt by the notified owner of the notice, whichever is later.

  1. No Sixty Day Limit for Risk Fee Notices When a Unit is Formed Around a Well Drilled or Drilling or When a Unit is Revised

Prior law required risk fee notices to be sent within sixty (60) days of the date of the unit order: (1) to nonparticipating owners in a unit created around a well already drilled or drilling; or (2) to owners of additional tracts included in a revised unit.  The amendment eliminates the sixty (60) day requirement.

  1. Expressly Provides That Failure to Send Notices to All Owners Does Not Invalidate Remaining Notices

The risk fee statute, as amended, states that an owner drilling, intending to drill, or who has drilled a well serving the unit may notify “all other owners in the unit” of the drilling or intent to drill and give each owner an opportunity to elect to participate in the risk and expense of such well.

Prior law did not expressly address the effect of properly sending notices to less than all owners.  The amendment includes a statement that notices properly made to any owner are valid even if not all of the owners in the unit are properly notified.

For more information, contact Jeff Lieberman (jdlieberman@liskow.com).

Disclaimer: This Blog/Web Site is made available by the law firm of Liskow & Lewis, APLC (“Liskow & Lewis”) and the individual Liskow & Lewis lawyers posting to this site for educational purposes and to give you general information and a general understanding of the law only, not to provide specific legal advice as to an identified problem or issue.  By using this blog site you understand and acknowledge that there is no attorney client relationship formed between you and Liskow & Lewis and/or the individual Liskow & Lewis lawyers posting to this site by virtue of your using this site.  The Blog/Web Site should not be used as a substitute for legal advice from a licensed professional attorney in your state regarding a particular matter.

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