GOM

By Tod J. Everage

With less than one week on the job, newly-confirmed Secretary of the Interior, Ryan Zinke announced that BOEM will offer 73,000,000 acres of lease space located in the Gulf of Mexico for oil and gas exploration. Proposed Lease Sale 249 is currently scheduled for August 16, 2017, and will include all unleased areas of federal waters in the GOM. The sale will be livestreamed from New Orleans.

This sale is the first under the new Outer Continental Shelf Oil and Gas Leasing Program for 2017-2022 (Five Year Program). The plan includes two GOM lease sales each year, including all available blocks in the combined Western, Central, and Eastern GOM. It is estimated that there are approximately 211 million to 1.118 billion barrels of oil and 0.547-4.424 trillion cubic feet of gas available for production in those available leases. The available land for lease includes approximately 13,725 unleased blocks located between 3-230 miles offshore, and ranging in depth between 9-11,115 feet of water.

Excluded from the lease sale are blocks subject to the Congressional moratorium established by the Gulf of Mexico Energy Security Act of 2006; blocks that are adjacent to or beyond the U.S. Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap; and whole blocks and partial blocks within the current boundary of the Flower Garden Banks National Marine Sanctuary. The full text of BOEM’s press release can be found here.

The current Five Year Program [2012-2017] will have its final lease sale today, March 22, 2017, which includes approximately 48 million acres off the coast of Louisiana, Mississippi, and Alabama comprised of 9,118 blocks. The sale will be livestreamed started at 9 am via BOEM’s website.

EPA

By Brittany Buckley Salup

On March 2, 2017, the EPA withdrew its information collection request (ICR) regarding methane emissions from existing oil and gas facilities.  EPA finalized and issued the underlying ICR on November 10, 2016.  Since that time, EPA sent letters to thousands of owners and operators in the oil and gas industry, requiring them to complete surveys regarding their existing facilities.  EPA’s withdrawal of the ICR is effective immediately.  According to the EPA’s website,  industry members who previously received a letter requiring a survey response associated with this particular ICR are “no longer required to respond.”

Additional information is available here.

 

marsh-sunset1

By Claire Juneau

Governor John Bel Edwards has sued Louisiana Attorney General Jeff Landry over Mr. Landry’s refusal to approve certain private legal counsel contracts. Governor Edwards alleges that Mr. Landry is the “chief legal officer of the state,” is “charged with the assertion or protection of any right or interest of [Louisiana],” and “is ethically required by the Rules of Professional Conduct promulgated by the Louisiana Supreme Court to abide by [his] client’s decisions concerning the objective of representation and to consult with [his] client as to the means by which they are to be pursued.” Governor Edwards seeks the immediate issuance of an alternative writ of mandamus compelling Mr. Landry “to perform his statutory ministerial duty to give written approval of the choice of counsel of the executive branch entities…” Governor Edwards alleges that Mr. Landry has rejected most of the contracts “on the grounds that the contracting attorneys should not have agreed not to discriminate in employment and the rendering of services in accordance with Executive Order No. JBE 2016-11.”

Governor Edwards alleges that the procedures for retention and employment of private counsel for the State of Louisiana are found in Louisiana Revised Statute § 42:262 and Louisiana Revised Statute § 49:258. Specifically, Revised Statute § 42:262(F)(1) provides in pertinent part:

In the event it should be necessary to protect the public interest, for any state board or commission to retain or employ any special attorney or counsel to represent it in any special matter for which services any compensation is to be paid, the board or commission may retain or employ such special attorney or counsel solely on written approval of the governor and the attorney general and pay only such compensation as the governor and the attorney general may designate or approve in the written approval.

And Revised Statute § 49:258 provides in pertinent part:

Notwithstanding the provisions of any other law to the contrary and specifically the provisions of any law that authorizes the state or a state agency to appoint, employ, or contract for private legal counsel to represent the state or a state agency, including but not limited to the provisions of R.S. 42:261, 262, and 263, and R.S. 40:1299.39(E), any appointment of private legal counsel to represent the state or a state agency shall be made by the attorney general with the concurrence of the commissioner of administration.

Governor Edwards argues that Revised Statute § 42:262 cannot be read alone and the discretion set forth with respect to boards and commissions is superseded by Revised Statute 49:258, which sets forth a “ministerial process for approval of private counsel, by both the Division of Administration and the Attorney General, and appointment by the Attorney General.” Governor Edwards asserts that Mr. Landry “has refused to perform” this ministerial duty.

A copy of the Petition for Writ of Mandamus can be found here:  Edwards v Landry.

 

louisiana

By Linda Akchin and Chris Dicharry

INTRODUCTION

Louisiana law imposes a sales tax on “sales at retail.”  “Sale at retail” is defined in the sales tax law, and the definition provides that the term does not include “sales of materials for further processing into tangible personal property for sale at retail.”    This provision is commonly referred to as the “further processing exclusion.”[1]  The most recent Louisiana Supreme Court’s decision interpreting this “further processing exclusion,” Bridges v. Nelson Indus. Steam Co., 2015-1439 (La. 5/3/16), 190 So.3d 276 (the “NISCO decision”), recently became final.  The decision is significant for all taxpayer-manufacturers.  It provides an excellent explanation of applicable legal principles relating generally to interpretation of the further processing exclusion and a comprehensive explanation of the three-prong jurisprudential test for application of the exclusion.  In response to the NISCO decision, and before it became final, the Legislature passed an Act amending the further processing exclusion.[2]  The purpose of this writing is to (i) provide some general information regarding applicable rules of law to be gleaned from the NISCO decision; and (ii) identify questions arising from the recent legislative amendment to the law.

THE SUPREME COURT DECISION

The further processing provision applies to byproducts.

The NISCO decision is the first in which the Supreme Court directly addresses the question of whether the further processing exclusion from tax applies to purchases of materials that are further processed into a byproduct of a manufacturing process.  The Supreme Court held that it does.  Noting that the exclusion applies to “tangible personal property,” and the sales tax regulation interpreting the exclusion provides that whether materials are further processed or simply used in the processing activity will depend entirely upon an analysis of the “end product,” the court reasoned that it found nothing in the law that requires the “end product” be the enterprise’s primary product, explaining:

“The plain language of the statute makes the exclusion applicable to articles of tangible personal property.  There simply is no distinction between primary products and secondary products. . . . At the end of the day, the ash [NISCO’s byproduct] is produced and sold . . . making it an ‘article of tangible personal property for sale at retail.’”[3]

The NISCO decision applies and interprets the long-established three-pronged test for application of the exclusion.

The Court applied the jurisprudentially-established three-pronged test for application of the further processing exclusion as it related to NISCO’s ash byproduct:  The test is:

(1) the raw materials become recognizable and identifiable components of the end products;

(2) the raw materials are beneficial to the end products; and

(3) the raw materials are materials for further processing, and as such, are purchased with the purpose of inclusion in the end products.[4]

In applying the test the Court clarifies and reinforces aspects of the application of the test that all taxpayers would be well-served to keep in mind.   Those clarifications include:

(1)       The further processing provision constitutes an “exclusion” not an “exemption” from tax, and as such, must be liberally construed in favor of the taxpayer;[5]

(2)       When the material purchased is processed into less than all of the end products produced, the analysis involves only consideration of the end product(s) into which the material is further processed, without regard to other end products.[6]

(3)       In order to satisfy the “benefit” prong of the test it is not necessary to conduct tests to determine the qualities of the material purchased or its beneficial impact on the end product.  It is sufficient that elemental components of the material purchased become integral components of the molecular makeup of the end product.  That “integration” is in and of itself of some benefit to the end product.[7]

(4)       The “purpose” prong of the test does not involve a primary purpose test; and the “purpose” test involves a “manufacturing purpose” inquiry, not a “business purpose” or “economic purpose” inquiry.  Only the manufacturing process and the physical and chemical components and the materials involved in the process are germane to the “purpose” test.[8]

(5)       There is no legal basis for an “apportionment” approach to the further processing exclusion, whether based upon the percentage of the material or some assigned value of the components that actually end up in the end product, and any such approach is impractical in application.[9]

The New Law

The 2016 Legislative amendment, effective June 23, 2016, amends the law to provide that “[t]he term ‘sale at retail’ does  not include sale of materials for further processing into articles of tangible personal property for sale at retail when all of the criteria in Subsubitem (I) of this Section are met.[10]  Those criteria consist of a re-statement of the three-pronged test:  (1) the raw materials become a recognizable and identifiable component of the end product; (2) the raw materials are beneficial to the end product; and (3) the raw materials are material for further process, and as such are purchased for the purpose of inclusion into the end product.

The amendment goes further, however, and adds a “Subitem II” to the definition of “sale at retail.”  This addition represents new law and provides, in short, that “[i]f the materials are further processed into a byproduct for sale, such purchases of materials shall not be deemed to be sales for further processing and shall be taxable.”  The term “byproduct” is defined to mean “any incidental product that is sold for a sales price less than the cost of the materials.”

QUESTIONS CREATED BY THE NEW LAW

Did the Legislature intend to overrule the NISCO decision?

The first question that arises is whether the clarifications to the three-prong jurisprudential test that are set forth in the NISCO decision may be applied under the amended law’s verbatim codification of the three-prong jurisprudential test.  It is a well-accepted rule of statutory construction that those who enact statutory provisions are presumed to act deliberately and with full knowledge of existing laws on the same subject, with awareness of court cases and well-established principles of statutory construction, with knowledge of the effect of their acts and a purpose in view; and that when the Legislature changes the wording of a statute, it is presumed to have intended a change in the law. [11]  Thus, legislative language will be interpreted based upon assumption that the Legislature was aware of judicial decisions interpreting those statutes, including among others, the NISCO decision.[12]  Because the amended law adopts the three-prong judicial test verbatim, we believe a strong argument may be made that there is no legislative intent to vary from the Supreme Court’s interpretations of that test, except to the extent the language of the amended law expressly varies from the Supreme Court’s prior interpretations.  The Legislature has never hesitated to expressly state its intent to legislatively overrule a Louisiana Supreme Court decision, when that is indeed its intent.  Here, no express statement of such intent was made, and we do not believe that the Louisiana Supreme Court will infer intent to overrule any aspect of the NISCO decision, except to the extent the language of the amendment is inconsistent with the court’s interpretation in NISCO.

What constitutes a “byproduct” for purposes of the new law?

In cases where a product is sold for a sales price less than the cost of its materials, questions will likely arise as to whether the product is an “incidental product.”  Because the term “incidental product” is not statutorily defined by the legislature, we must give the words their commonly-accepted meaning.  The word “incidental” means “being likely to ensue as a chance or minor consequence,” or “occurring merely by chance or without intention or calculation.”[13]  Many products sold for a sales price less than the cost of their materials are intentionally manufactured and sold.  They are not manufactured by accident; and they are not the result of chance.  Instead, a conscious decision is made to choose a process design that will in fact create certain byproducts, with the intention to sell all the products of the process – both “primary products” and “byproducts,” with an overall profit motive.  While any particular byproduct may be of minor consequence economically speaking, when viewed in a vacuum, it may not be of economic “minor consequence” to the overall finances of the taxpayer; or it may not be of minor consequence in terms of volumes manufactured and sold, or investment made to develop, manufacture, market and sell the byproduct.  In our opinion, the Legislature’s amendment – a clear intent to vary from the NISCO decision’s holding that the further processing exclusion applies to all end products – merely creates more uncertainty, resulting in many more sales and use tax disputes and consequent litigation.  The taxing authorities will undoubtedly argue that the intent of the amendment was to create a rule to be applied when a byproduct, viewed in a vacuum, is not profitable; but that is not what the Legislature said.  The Legislature adopted a rule to be applied to “incidental products,” without defining that term.  Thus, we believe a proper interpretation requires that a determination must first be made regarding whether the byproduct is an “incidental product;” and only if it is an incidental product, does the second part of the “test” – whether it is sold for a sales price less than the cost of its material – apply.

May the new law be applied retroactively?

Taxpayers may expect the taxing authorities to impose the new law going forward.  Serious questions arise, however, regarding the applicability of the new law to taxes already reported and paid, or incurred, before the new law became effective.

The new law expressly provides that it “shall not be applicable to any existing claim for refund filed or assessment of additional taxes due issued prior to the effective date of this Act for any tax period prior to July 1, 2016, which is not barred by prescription.”  If a taxpayer’s claim or dispute with the taxing authority falls within the language of this provision, the new law should not be applied by the taxing authorities.  It is not clear what is meant by the terminology “claim for refund filed.”  Does it mean the submission of a refund request or claim with the taxing authority, or a suit for refund, or both?  Likewise, it is not clear what is meant by “assessment of additional taxes due issued” – does it include notices of intent to assess (“proposed assessments”), notices of assessment (“final assessments”), petitions for redetermination of assessments, or suits to collect tax, or all four.  We recommend that taxpayers apply the most liberal interpretation of the language unless and until guidance is provided by regulation or judicial decision.

There will undoubtedly be cases in which no claim for refund has been filed or assessment issued before the effective date of the act, but involving tax periods prior to July 1, 2016.  In such cases, we believe a strong argument may be made that retroactive application of the new law to pre-amendment tax periods is unconstitutional.  The Legislature stated in the Act that it “is intended to clarify and be interpretive of the original intent and application of” the further processing exclusion, and that “[t]herefore, the provisions of this Act shall be retroactive and applicable to all refund claims submitted or assessments of additional tax due which are filed on or after the effective date of this Act.”  Despite this statement by the legislature, we believe that the amendment to the law is not merely clarifying and interpretive.  We believe the changes are substantive in nature.  Generally, substantive laws may be applied prospectively only.  And despite express legislative intent to the contrary, it is uniquely the province of the courts to determine if an Act is substantive, or merely clarifying and interpretive.  And, if the law is substantive, it will not be applied retroactively by the courts because to do so impinges upon the authority of the judiciary in violation of the constitutional doctrine of separation of powers and divests taxpayers of substantive rights and causes of action that accrued and vested in the taxpayer before the effective date of the Act, such that imposition of the new law would constitute a denial of due process.[14]

Was the amendment to the law constitutionally enacted?

In the case of an attempt by a taxing authority to apply the new law retroactively to pre-amendment tax periods, or in the case of a purely prospective application of the new law to post-amendment tax periods, a question still exists regarding the constitutionality of the law’s enactment.  The Louisiana Constitution provides that enactments levying a new tax or increasing an existing tax require a two-thirds vote of both houses of the Legislature to become law.[15]  Here, the Act at issue did not have a two-thirds vote of the House of Representatives.  A viable legal argument exists that because the law amends definitions in a manner that makes previously non-taxable transactions taxable, it constitutes either a “new tax” or an “increase in an existing tax,” thus requiring a two-thirds vote of both houses of the Legislature. [16]  Unless and until this issue is resolved in the courts, a taxpayer would be wise to seek legal counsel and consider its options before voluntarily paying tax on materials purchased for further processing into a byproduct.

__________________________________________________________

[1] La. R.S. 47:301(10)(c)(i)(aa), before amendment effective June 23, 2016; see La. Act No. 3 (2nd Extra. Sess. 2016) (“Act 3 of 2016”).

[2] Act 3 of 2016, supra.

[3] NISCO, pp. 8-9, 190 So.3d at 282.

[4] Id. at pp. 7-8, 190 So.3d at 281, quoting International Paper, Inc. v. Bridges, 2007-1151, p. 19 (La. 1/16/08), 972 So.2d 1121, 1134.

[5] Id. at pp. 5-6, 190 So.3d at 280-281.

[6] Id. at pp. 7-9, 190 So.3d at 281-282.

[7] Id. at pp. 9-10, 190 So.3d at 282-283.

[8] Id. at pp. 4, 10-13, 190 So.3d at 279, 283-285/

[9] Id. at pp. 13-15, 190 So.3d at 285-286.

[10] Act 3 of 2016, supra (emphasis added)

[11] Borel v. Young, 2007-0419, pp. 8-9 (La. 11/2/07), 989 So.2d 42, 48 (emphasis added).

[12] State v. Campbell, 2003-3035, pp. 8-9 (La. 7/6/04), 877 So.2d 112, 118.

[13] Merriam-Webster’s Collegiate Dictionary (11th ed. 2012) (emphasis added).

[14] See e.g. Mallard Bay Drilling, Inc. v. Kennedy, 2004-1089 (La. 6/29/05), 914 So.2d 533); Unwired Telecom Corp. v. Parish of Calcasieu, 2003-0732 (La. 1/19/05), 903 So.2d 392; and Bourgeois v. A.P. Green Indus., Inc., 2000-1528 (La. 4/3/01), 783 So.2d 1251; La. Const. Art. II, §§1-2; La. Const. art. I, §2; U.S. Const. Amend. XIV, §1.

[15] La. Const. Art. VII, §2.

[16] See e.g. Dow Hydrocarbons & Resources v. Kennedy, 1996-2471 (La. 5/20/97), 694 So.2d 215.

 

 

marsh

By Matthew B. Smith

The first of many coastal land loss lawsuits filed by Louisiana coastal parishes has proceeded to judgment, with the result being the dismissal of the case based on the failure to exhaust administrative remedies prior to filing suit.

Since the filing of the politically-charged Southeastern Louisiana Flood Protection Authority lawsuit, four parishes – Plaquemines, Jefferson, and more recently Cameron and Vermilion – have filed 40 similar lawsuits against oil and gas exploration and production companies, and pipeline companies, alleging that these companies violated the State and Local Coastal Resources Management Act of 1978 (“SLCRMA”) and, in doing so, caused or contributed to coastal land loss. The foundation of the parish plaintiffs’ claims is that the oil and gas companies performed certain activities in Louisiana’s coastal zone either (i) without the Coastal Use Permits required by the SLCRMA or (ii) or in violation of the Coastal Use Permits which were issued under the SLCRMA. Recently, the Louisiana Attorney General and the Louisiana Department of Natural Resources, Office of Coastal Management (the “Intervenors”) intervened in the lawsuits, joining with the parish plaintiffs in order to ensure the protection of the State’s interests.

The oil and gas company defendants have raised various exceptions to the claims of the parishes and Intervenors, including the defense that the lawsuits are premature because the plaintiffs failed to pursue the administrative remedies available under the SLCRMA and related regulations prior to filing suit. This argument was considered in the case of The Parish of Jefferson v. Atlantic Richfield Company, et al., No. 732-768, 24th Judicial District Court, Jefferson Parish, with Judge Stephen D. Enright, Jr. issuing a Judgment on August 1, 2016 (published on August 8, 2016) agreeing with the oil and gas company defendants and dismissing the claims of Jefferson Parish and the Intervenors as premature for failure to exhaust administrative remedies.

In his Judgment, Judge Enright found that a comprehensive administrative remedy exists under the SLCRMA and the Louisiana Administrative Code (particularly La. Admin. Code tit. 43, pt. I sec. 723(D)(1-4)) to address potential violations of Coastal Use Permits. Accordingly, the Court ordered that Jefferson Parish and the Intervenors must pursue and exhaust this administrative remedy process prior to bringing suit in court seeking civil damages. As the Court stated, “in the absence of an exhaustion of administrative remedies, it is yet to be determined whether civil damages exist.”

While Jefferson Parish has indicated that it will file a motion for a new trial and/or appeal to the Louisiana Fifth Circuit, the Louisiana Attorney General Jeff Landry issued a statement on August 10, 2016, indicating that he will not seek to challenge Judge Enright’s ruling because the ruling is protective of the State’s interest, in that it allows the Louisiana Department of Resources to determine whether any violations of Coastal Use Permits have occurred through the administrative process established by the SLCRMA and the Louisiana Administrative Code. As stated by Attorney General Landry:

addressing the issues associated with permit violations through the administrative process is a cost-effective, efficient way to resolve any violations. That was clearly the purpose of the Legislature creating this regulatory scheme. I believe the Secretary of the Department of Natural Resources has been given ample tools by the Legislature to address these issues.

Full Statement.

While a victory for the oil company defendants, it is still expected that additional parishes will file coastal land loss lawsuits. We will continue to report on key developments in these cases.

 

ogw

By Will Huguet

Terminology employed in oil and gas exploration may often become antiquated. In this regard, this comment is intended to introduce the reader to the dated and potentially confusing terms “mineral acre” and “royalty acre.” Although the author is not a large proponent of the use of such terms, they are part of the fabric of mineral and royalty deeds and will continue to be utilized for the foreseeable future.

Mineral Acre Discussion

A “mineral acre” is a full mineral interest in one (1) acre of land.  One may ask – why not simply say “acre” when a full interest in one (1) acre equals one (1) mineral acre?  It is surmised that use of “mineral acre” sprung from concerns over warranty and quantifying what is to be sold.  In this respect, if the exact acreage of a tract is unknown, e.g. somewhere between 45-50 acres, or undivided ownership is unknown, e.g. the person either owns a 3/5 interest or 4/5 interest in a tract, a mineral purchaser may seek to protect itself by establishing a floor and buying a set number of mineral acres. For example, in a scenario wherein a seller is to convey fifty percent (50%) of their interest in a “50 acre” tract, but the exact acreage is unknown, a prudent buyer may set forth that they are purchasing 25 mineral acres. In the event that a survey (or other title impediment) reveals that the tract actually comprises 45 acres, the buyer would receive a mineral servitude covering 25 net acres (with the vendor now owning 20 net mineral acres), rather than 22.5 acres under the fifty percent (50%) conveyance language. In summary, although the term “mineral acre” is fairly basic to grasp, there still may be areas of confusion pertaining to multiple tracts and inadvertently blending the concept with those of royalty, etc.

Royalty Acre Discussion

A “royalty acre” appears to have been originally conceptualized as the full lease royalty on one (1) acre of land, i.e. the lessor’s royalty. As the longstanding (but now largely inapplicable) lessor’s royalty was one-eighth (1/8), if one purchased one (1) royalty acre from a landowner subject to a mineral lease with a one-eighth (1/8) lessor’s royalty, that party would be buying all of the royalty payable to the landowner under said lease. Over time, it appears that the term “royalty acre” became disconnected from lease royalty and came to mean a “1/8 royalty on the full mineral interest in one acre of land.” See Dudley v. Fridge, 443 So.2d 1207, 1208 (Alabama 1983). Stated alternatively – one (1) mineral acre came to be equated with eight (8) royalty acres.

However, some scholars and commentators (like Williams & Meyers) counter that “royalty acre” should continue to reflect a full lease royalty. In other words, if a landowner is subject to a one-fourth (1/4) lessor’s royalty on one (1) acre of land and sells one (1) royalty acre, then such grant would cover the full lessor’s royalty interest. However, if one (1) mineral acre equals eight (8) royalty acres, a one-fourth (1/4) lessor’s royalty on a one (1) acre tract would yield two (2) royalty acres and only transfer one half (1/2) of the grantor’s lessor’s royalty. There is Louisiana case law on this matter, which appears to embrace the definition that a “royalty acre” equates to a “1/8 royalty on the full mineral interest in one acre of land,” as discussed in following.

In Thibodeaux v. American Land & Exploration, Inc., 450 So.2d 990 (La. App. 3 Cir. 1984), the Court noted the following in footnote 3:

Supple testified that the term “royalty acre” is a commonly used industry term. He also stated that production distribution is based on the ownership of royalty acres which are derived by converting ordinary acreage into royalty acreage on the basis of the standard one-eighth (1/8) royalty, which was the fraction ordinarily reserved by owners leasing their land for oil production. Thibodeaux had, however, reserved a one-fifth (1/5) royalty interest in the production under his lease with Stone Oil, thus creating more royalty acreage on the land than would have existed under a one-eighth (1/8) reservation.

Harrison and Supple both calculated that the 29.5 acres owned by Thibodeaux and his children contained 47.2 royalty acres. [1]  In his deed to American Land, Thibodeaux transferred one-half of his one-half interest, or one-fourth of the total (or 11.8) royalty acres.

Therefore, Louisiana appears to have adopted the position (albeit with limited authority), that one (1) mineral acre includes eight (8) royalty acres regardless of the lessor’s royalty. However, due to this issue, prudent parties often specifically define “royalty acres” in a royalty deed. [2]  Using this definition, if one (1) acre of land is subject to a one-eighth (1/8) lease, there is one (1) royalty acre available to the lessor, if subject to a three-sixteenths (3/16) royalty lease, the lessor is entitled to one-and-one-half (1.5) royalty acres, and if subject to a one-fourth (1/4) royalty lease – two (2) royalty acres. [3]  Returning to the rationale behind use of “mineral acres,” if attempting to buy fifty percent (50%) of a landowner’s royalty interest in one (1) acre of land under a one-fourth (1/4) royalty lease, one could set forth that they are buying 1 “royalty acre.” In doing so, if the tract is ultimately found to only comprise 0.8 acres, then the purchaser owns a mineral royalty covering 0.5 acres, whereas the seller will only be entitled to the royalty on the remaining 0.3 acres.

Additional Issues

The reader is further advised of a couple of additional problems which may be encountered in conveyancing. The first is the use of inconsistent and potentially conflicting grants – such as using both a stated percentage of the grantor’s interest and specifying the exact mineral acres or royalty acres conveyed. This may be remedied by avoiding the conflict or clearly stating which is to control, e.g. the intent is to convey one-half (1/2) of grantor’s interest, but the specific figure will control in the event of a conflict. Further, when the grant covers several tracts or involves several units, attribution issues may be encountered. The undersigned has reviewed royalty deeds wherein several tracts were covered and the tracts included differing undivided ownership, were subject to different mineral lease burdens, or presented distinct title issues. In such an event, issues with attribution of the stated gross mineral or royalty acres to specific tracts may be encountered, which may potentially be remedied by separately listing the mineral or royalty acres to be conveyed with respect to each separate tract.

Will Huguet has assisted buyers and sellers in numerous transactions involving mineral and royalty deeds, including title, curative, negotiation, and drafting the involved instruments.

_____________________________________________________

[1] Which would be calculated as follows: 29.5 x 8 x 1/5 = 47.2. 

[2]  An example would be as follows: “When used herein, the term ‘Royalty Acre’ means and includes a mineral royalty interest in 1/8 of 8/8 in and under one (1) acre of land.”

[3]  Note that under this formulation, if one (1) royalty acre is sold subject to a 1/8 mineral lease and said lease lapses and the landowner enters into a new mineral lease with a 1/4 lessor’s royalty, the royalty purchaser and landowner would each be entitled to 1/2 (or 1/8 each) of the lessor’s royalty.

 

wet

By Sam O. Lumpkin

On May 31, 2016, the US Supreme Court ruled in United States Army Corps of Engineers v. Hawkes Co., Inc. that a jurisdictional determination issued by the Corps of Engineers under the Clean Water Act constitutes a final agency action that is judicially reviewable under the Administrative Procedure Act.  Justice Roberts wrote the decision of the Court, to which all other justices joined or concurred in the result.

The Clean Water Act prohibits the unpermitted discharge of any pollutant into “the waters of the United States,” including wetlands, without a permit.  However, only wetlands with a “significant nexus” to other waters of the United States are within Corps and EPA Clean Water Act jurisdiction.   Rapanos v. United States, 547 U.S. 715 (2006).  Dredging and filling activities are considered to be the discharge of a pollutant.   As a result, any dredging or filling activities involving a waters of the US within Corps jurisdiction must be approved beforehand by the US Army Corps of Engineers, which is responsible for issuing permits for discharges that would otherwise be forbidden by the Clean Water Act. The Clean Water Act allows imposition of potentially massive criminal or civil penalties for discharging any pollutant without a permit.

Determination of what constitutes a “wetland” or “other waters” of the US often involves expert determinations.  Further, the process for obtaining a Corps permit can itself be time-consuming and expensive – the Court noted that the average applicant for the type of permit at issue in Hawkes spends “788 days and $271,596 in completing the process,” and “[e]ven more readily available ‘general’ permits took applicants, on average, 313 days and $28,915 to complete.” To aid applicants, the Corps issues “jurisdictional determinations” (“JDs”) on a case-by-case basis. JDs are either “preliminary” – advising that there may be waters of the United States on a piece of land – or “approved,” which definitively states the presence or absence and extent of such waters.  The JDs provide some certainty for a landowner or developer as to whether they are required to endure the permitting process. The approved JDs are administratively appealable to the Corps; however, until the Hawkes decision, it was unclear as to whether judicial review of the Corp decision was available.

In Hawkes, the applicant sought a jurisdictional determination and was granted an approved JD stating that the property contained “water of the United States,”with a delineation of where those waters were located. Central to the case was whether the wetlands had a close enough nexus to a major river 120 miles away such that they were within the Corps’ jurisdiction. The applicants administratively appealed the JD under 33 C.F.R. Part 331, and the Corps reaffirmed its decision with revisions to the extent of the wetlands. Not satisfied, the applicants sought review of the JD in a federal district court under the Administrative Procedure Act (APA), which allows district courts to review “final agency actions.” 5 U.S.C.A. § 704. The Corps argued that judicial review was available only at the time of the final permitting decision or on an enforcement action commenced for dredge or fill activity without a permit. The district court agreed with the Corps and dismissed for lack of jurisdiction, holding that a JD is not a “final agency action.” 963 F.Supp.2d 868 (Minn. 2013). The applicants then appealed to the US Court of Appeals for the Eighth Circuit, which reversed. 782 F.3d 994 (2015).

The Supreme Court agreed with the Eight Circuit, holding not only that an “approved” JD is a final agency action, but also that there are no adequate alternatives to the APA for challenging a Corps JD in court. On the issue of finality, the Court noted that  JDs give rise to “direct and appreciable legal consequences,” and they are also binding on the Corps and the EPA for five years following the determination.[1] Unlike other possible agency actions which are merely advisory, such as informal advice from an agency or a preliminary JD, an approved JD follows extensive fact-finding, marks “the consummation of the agency’s decision-making process” and constitutes a final determination of rights and obligations “from which legal consequences will flow.” The Court further held that there are no adequate alternatives to an APA challenge to the Corps’ JD, noting that the only alternatives available were to forego a permit altogether or proceed with the permitting process. Without a permit, the applicant could either proceed with its proposed activity and be exposed to the civil and criminal penalties of the Clean Water Act, or abandon its proposed activity altogether. But the permitting process also poses a highly expensive, time-consuming, and uncertain proposition, for which judicial review would only be available when complete. As a result, the Court held that an approved JD is reviewable in federal district court under the APA.

The Hawkes ruling is a narrow one, and applies only to approved JDs. However, because JDs are literally determinations of the extent of the Corps’ jurisdiction, the scope of the Corps’ authority will likely be subjected to many more challenges than in the past, when such objections would have to wait until the permitting process was complete. As a result, in the future the Corps’ jurisdiction may face additional restraints imposed by federal courts.

Because an adverse ruling on an approved JD is appealable beyond the Corps after Hawkes, a thorough record in the initial JD proceeding is more important than ever. Ordinarily, a consultant will prepare a draft JD for submission to the Corps, which may or may not visit the site in question; the Corps then issues its decision on the record. This process, however, does not offer the applicant any further opportunity to develop the record. Any administrative appeal and subsequent judicial review is limited to the administrative record before the Corps, unless good cause is demonstrated as to why additional information should be admitted. As a result, applicants should ensure that their consultant’s initial submittal is thoroughly documented and, possibly, subjected to legal review prior to submission. Because federal district courts do not possess the same expertise as the Corps, a well-documented and clearly explained initial proposal will aid a district court with the information it needs to review the Corps’ decisions.

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[1]  There were three concurring opinions taking differing positions on whether a Memorandum of Agreement between the Corps and EPA makes the JDs binding on EPA. This aspect could bear further review.

Storm-And-Blue-Lightining-At-Sea

By Tod Everage

Last December, we posted an article addressing the recent conflicted decisions out of the Eastern District of Louisiana on the remaining availability of punitive damages against third parties under general maritime law. You can find that article here. In 2016, the conflict continues…

As we mentioned, Judge Fallon allowed a claim for punitive damages against a third party under general maritime law to proceed against a third party on the basis that the prohibition against such damages set forth in Scarborough v. Clemenco Indus., 391 F.3d 660 (5th Cir. 2004) was indirectly abrogated by Atlantic Sounding v. Townsend, 557 U.S. 407 (2009). See Collins v. A.B.C. Marine Towing, LLC, 2015 WL 5254710 (E.D. La. 9/9/2015). Therein, Judge Fallon held that a seaman can recover punitive damages under general maritime law if the Jones Act is not implicated. A few months later, Judge Morgan twice held the opposite view. See Howard v. Offshore Liftboats, LLC, 2015 WL 7428581 (E.D. La. 11/20/15); Lee v. Offshore Logistical and Transports, LLC, 2015 WL 7459734 (E.D. La. 11/24/15). In Judge Morgan’s opinion, Scarborough remains precedent in the Fifth Circuit.

Last month, Judge Zainey joined the fray in Hume v. Consolidated Grain & Barge, Inc., 2016 WL 1089349 (E.D. La. 3/21/16). That case involved personal injury claims of two workers, working for Consolidated Grain & Barge (“CGB”) aboard the M/V BAYOU SPECIAL. At the time of the incident, the M/V BAYOU SPECIAL was being pushed by the M/V MR. LEWIS, which was owned and operated by Quality Marine. Plaintiffs sued CGB and Quality Marine, asserting the usual array of claims under the Jones Act and general maritime law, including a demand for punitive damages. In response to a Motion to Dismiss filed by Quality Marine, Plaintiffs conceded that their punitive damages claims were unavailable against Quality Marine for Jones Act negligence and unseaworthiness; however, they contested Quality Marine’s argument that punitive damages were unavailable under the general maritime law.

Not surprisingly, Quality Marine relied upon McBride and Scarborough to argue that punitive damages are not available to the Plaintiffs. In Opposition, Plaintiffs relied on Judge Fallon’s decision in Collins. Judge Zainey found Judge Fallon’s reasoning in Collins persuasive and denied Quality Marine’s motion. Judge Zainey agreed that “there is no need for uniform treatment of an employer and a third party tortfeasor where there is no statutory remedy that is different than the general maritime law remedy.” Because the Jones Act is not implicated by Plaintiffs’ punitive damages claims against Quality Marine, the prohibition of such claims under the Jones Act has no bearing. Accordingly, Plaintiffs’ claims for punitive damages against Quality Marine were allowed to proceed.

The current score sits at 2-1 in favor of punitive damages against a third party under general maritime law. Until the U.S. 5th Circuit weighs in to settle this issue, the availability of such claims appears to be guided by the judicial lottery.

Kean Miller Industrial Strength Law

By Chris Dicharry and Jason Brown

The Louisiana Corporation Franchise Tax (“CFT”) has historically been imposed only on corporations. Thus, LLCs and partnerships have not been subject to the CFT. In the Special Session that ended last March, the Louisiana Legislature expanded the companies subject to the CFT to include non-corporate entities that elect to be taxed as corporations for federal income tax purposes. See, La. Acts 2016 (1st Ex. Sess.), No. 12 (“Act 12”).  The new law provides a safe harbor for LLC’s “qualified and eligible to make an election to be taxed” as an S-Corporation. Yet, while Act 12’s plain language does not appear to require that an LLC actually make the S-Corporation election to qualify for the safe harbor, the Louisiana Department of Revenue (“LDR”) has informed Kean Miller that LDR policy may require that an LLC actually make the election to avoid the CFT.

The expanded CFT law also legislatively overrules the taxpayer-favorable UTELCOM case. UTELCOM, Inc. v. Bridges, 2010-0654 (La. App. 1 Cir. 9/12/11), 77 So.3d 39. Under UTELCOM, a corporation was found not to be doing business in the state of Louisiana so as to be subject to the CFT, when its only activity in Louisiana was as a limited partner in a partnership doing business in Louisiana. The court found that the law did not extend to corporations that were not directly (and only passively, through ownership) engaged in business in Louisiana. The new law expands the activities that will subject an entity to the CFT by including the following as one of the taxable incidents in Louisiana:

“The owning or using any part or all of its capital, plant, or other property in this state whether owned directly or indirectly by or through a partnership, joint venture, or any other business organization of which the domestic or foreign corporation is a related party as defined in R.S. 47:605.1.”

Thus, owning an interest in an entity with operations in Louisiana may subject the owner to the CFT. Unfortunately, the CFT may end up being tiered under these circumstances. The entity operating directly in Louisiana may be subject to the CFT depending on how it is taxed for federal income tax purposes and its ability to elect S-Corporation treatment; and the interest owner may also be subject to CFT based on its investment in the entity with Louisiana operations.

For example: If Alligator Energy Corporation has no operations in Louisiana, but holds a 60% ownership interest in Alligator Pipeline, LLC, a Louisiana LLC that operates exclusively in Louisiana, Alligator Pipeline, LLC will be subject to the CFT if it is taxed as a corporation for federal tax purposes and is not eligible to be taxed as an S-Corporation. Alligator Energy Corporation will also pay CFT based on its investment in Alligator Pipeline, LLC. In essence, the activities of Alligator Pipeline, LLC will be taxed twice – once at the operating entity level and once at the parent level.

Act 12 does add a new holding company deduction; however, the deduction is only available if the parent has at least 80% of the voting and nonvoting power of all classes of stock, membership, partnership, or other ownership interests in the “subsidiary.”

Act 12 is applicable to tax periods beginning on or after January 1, 2017; however, this effective date could be misleading. Historically, a corporation subject to the CFT paid an initial CFT of $10 for its first year of operation. Under Act 12, an existing entity that becomes subject to the CFT because it is taxed as a corporation for federal income tax purposes (and cannot use the S-Corporation safe harbor) will be subject to full CFT liability based upon its books and records for the prior year.

EPA

By Brittany Buckley Salup

The Environmental Protection Agency (EPA) announced in March that it is in the process of developing new regulations to curb methane emissions from existing oil and gas facilities.  The EPA will formally require companies operating existing oil and gas sources to provide information to assist in the development of comprehensive regulations to reduce methane emissions.  Methane is a potent greenhouse gas with a higher global warming potential than carbon dioxide.  As a preliminary step in the process of developing methane regulations for already-existing oil and gas facilities, EPA plans to present an Information Collection Request (ICR) for public comment (via notice in the Federal Register) by the end of April 2016.

An ICR is a formal records request that requires the recipient(s) to provide reporting, records, or other specified information directly to the EPA.  Such ICRs are authorized by Section 114(a) of the Clean Air Act (CAA), which provides EPA broad authority to request information, provided the requested information is for one of three approved purposes: (1) to assist the Agency in developing rules or regulations; (2) to determine whether “any person is in violation” of any CAA requirement; or (3) to carry out “any provision of this chapter[.]” The EPA is in the process of developing an ICR that will help it identify and target significant sources of methane emissions at existing facilities.  The ICR will likely call for mandatory record-sharing, equipment surveys, and/or emissions monitoring.  Recipients of the ICR will generally be required to provide the requested information to EPA and will be required to attest that their responses are accurate.  Members of the oil and gas industry can expect to receive this ICR later this year, after public comment and final administrative approval.

EPA’s recently-announced plan is the latest in a series of moves to limit methane emissions from oil and gas facilities; however, this is the first significant proposal to target already-installed wells and other existing oil and gas equipment.  In 2012, EPA adopted regulations that limit methane and other emissions from new hydraulically fractured and re-fractured natural gas wells. EPA proposed rules for reduction of methane and volatile organic carbon emissions from new oil and gas facilities on September 18, 2015.  80 Fed. Reg. 56593.  The proposed rules for new facilities imposed methane reduction measures on oil and natural gas well sites, natural gas gathering and boosting stations, gas processing plants and natural gas transmission compressor stations.  The March 2016 announcement for existing facilities indicates that the ICR will apply to these same types of sources “as well as additional sources.”  This latest announcement has fueled concerns that the forthcoming regulations could, as a practical matter, require the industry to retrofit or replace existing production and processing equipment to achieve compliance.

For more information, see EPA Administrator, Gina McCarthy’s blog post on this topic here.