Environmental Groups File Suit to Compel EPA to Review and Revise Oil and Gas Waste Regulations

On May 4, 2016, environmental groups sued the U.S. Environmental Protection Agency (EPA), seeking to compel EPA to “fulfill long-delayed nondiscretionary duties” under the Resource Conservation and Recovery Act (RCRA) by issuing revised regulations governing oil and gas wastes.  The complaint alleges that EPA’s regulations “are outdated, contain generic provisions that do not specifically address the modern oil and gas industry, and fail to adequately protect against potential harm to human health and the environment resulting from oil and gas wastes.”  According to the complaint, the harm allegedly includes the “potential carcinogenic effects of hydraulic fracturing flowback water” and the “increasing earthquakes” allegedly linked to injection wells used for oil and gas wastewater disposal.

The suit relies on RCRA Sections 2002(b) and 4002(b) (42 U.S.C. §§ 6912(b) and 6942(b)), which require EPA to review and, as necessary, revise RCRA regulations and guidelines for state solid waste management plans at least every three years.  The complaint alleges that EPA last conducted a review of its RCRA Subtitle D regulations for oil and gas wastes on July 6, 1988, “when it determined that it was necessary to revise the general Subtitle D regulations to promulgate ‘tailored’ regulations for oil and gas wastes.”  According to the complaint, EPA “has not completed these necessary revisions,” nor has it reviewed the Subtitle D regulations for oil and gas wastes since that time.  The complaint also alleges that EPA last reviewed its guidelines for state solid waste management plans in 1981, and since that time, “eleven successive three-year deadlines have passed with no further review or revision.”

The lawsuit is styled as Environmental Integrity Project, et al. v. McCarthy, Case No. 1:16-cv-00842-JDB, and was filed in the U.S. District Court for the District of Columbia.  The oil and gas industry will need to monitor this suit.  A similar lawsuit filed in 2012 in the same court resulted in a court opinion requiring EPA to review its RCRA Subtitle D regulations concerning coal ash.  See Appalachian Voices v. McCarthy, 989 F. Supp. 2d 30, 53-56 (D. D.C. 2013).  In that case, the parties eventually settled, and EPA agreed in a consent decree to finalize RCRA Subtitle D coal ash regulations by a certain date.

Forum Shopping Curtailed: Venue Limited to Parish Where Drilling Rig Was Lost

In a May 4, 2016 opinion, Louisiana’s Third Circuit Court of Appeal made clear that venue was not proper in Concordia Parish—where plaintiff filed suit for damages resulting from the loss of its drilling rig in LaSalle Parish—because:  (1) the tortious conduct allegedly occurred and damages from the loss of the drilling rig were sustained in LaSalle Parish only, despite plaintiff’s assertion that it lost profits at its domicile in Concordia Parish, and (2) not all defendants were parties to a contract executed in Concordia Parish, and the fact that there may exist joint liability among the defendants did not confer venue there.

In D&D Drilling & Exploration, Inc. v. XTO Energy, Inc., D&D Drilling & Exploration, Inc. (“D&D”) filed suit in the Seventh Judicial District Court of Concordia Parish against XTO Energy, Inc. (“XTO”), Alliance Drilling Consultants, LLC (“Alliance”), Clifton Pritchard, and Alliance’s insurer, James River Insurance Company (“James River”), for damages resulting from the loss of D&D’s drilling rig.  D&D alleged that Pritchard, an employee of Alliance, which XTO retained to operate the rig, failed to ensure that sufficient drilling mud was on hand at the rig, and that the lack of sufficient drilling mud caused a well blow out and subsequent fire that destroyed the rig in LaSalle Parish.

In response to the lawsuit in Concordia Parish, XTO filed an exception of improper venue and the other defendants subsequently filed similar exceptions.  The trial court denied defendants’ exceptions and James River, Alliance, and Pritchard filed a joint answer before all defendants sought supervisory writs.  The Third Circuit first denied writs but the Louisiana Supreme Court granted writs and remanded the matter to the Third Circuit for full briefing and argument.

Concordia Parish was not a proper venue as to any of the defendants pursuant to Louisiana’s general venue rules prescribed by Code of Civil Procedure article 42.  Instead, D&D invoked exceptions to the general venue rules, and therefore bore the burden of proof to establish venue in Concordia Parish.

First, D&D attempted to establish venue in Concordia Parish pursuant to Code of Civil Procedure article 74, which provides that “[a]n action for the recovery of damages for an offense or quasi offense may be brought in the parish where the wrongful conduct occurred, or in the parish where the damages were sustained.”  The drilling rig was lost in LaSalle Parish but D&D asserted that this case called for an extension of the concept of “where the damages were sustained” to include Concordia Parish, where D&D allegedly lost profits as a result of the loss of the rig.  The Third Circuit disagreed and, instead, adhered to “the legion of cases that hold that the parish where the wrongful conduct occurred is the parish where damages were sustained under Article 74.”  In its reasoning, the Third Circuit quoted Besler v. St. Paul Fire & Marine Ins., 509 So.2d 12, 18-19 (La. App. 1 Cir. 1987) as follows:

The common thread that runs through the Coursey-Foster-King-Williams-Lapeyrouse line of cases is that, if any damage is caused to the plaintiff in the parish where the wrongful conduct occurred, that parish, and no other, is “the parish where the damages were sustained” for purposes of Article 74. This holding is consistent with the jurisprudence that Article 74 must be strictly construed. This holding evidences public policy determinations by the Coursey-Foster-King-Williams-Lapeyrouse courts that forum shopping should be minimized in actions for the recovery of damages for offenses and quasi offenses.

The Third Circuit concluded that the loss of the rig was the basis of D&D’s lawsuit and because that loss occurred in LaSalle Parish, LaSalle Parish was the only proper venue under Article 74.

Second, D&D attempted to establish venue in Concordia Parish pursuant to Code of Civil Procedure article 76.1, which states that “[a]n action on a contract may be brought in the parish where the contract was executed . . . .”  D&D and XTO executed a contract in Concordia Parish. However, the Third Circuit explained that Article 76.1 would not extend venue to Alliance, Pritchard, or James River, even if they were joint or solidary obligors of XTO, “because the article that governs venue in the case of joint and solidary obligors, La. Code Civ. P. art. 73, limits its exception to proper venues under Article 42,” which did not confer venue in Concordia Parish as discussed above.  The Third Circuit also rejected D&D’s argument that a verbal agreement between D&D and Alliance conferred venue in Concordia Parish pursuant to Article 76.1, because D&D offered no evidence of such an agreement at the hearing on the exception.   Similarly, the Third Circuit rejected D&D’s argument that the retainer of Alliance and Pritchard by XTO constituted a contract for D&D’s benefit, creating a stipulation pour autri under Code of Procedure article 1978, because D&D offered no such evidence at the hearing on the exception.

Finally, D&D argued that Alliance, Pritchard, and James River waived their rights to object to venue because they filed answers before they filed their notice of intent to apply for writs.  The Third Circuit disagreed and concluded that the parties timely manifested their intent to apply for writs, adding that D&D’s assertion would effectively strip any defendant of the right to appeal an adverse ruling on an exception of venue, as opposed to seeking redress through an application for supervisory writs.

After rejecting each of D&D’s arguments to confer venue upon Concordia Parish, the Third Circuit granted defendants’ applications for writs peremptorily and ordered the matter transferred to the Twenty-Eighth Judicial District Court of LaSalle Parish.

Liskow and Lewis represented XTO in this proceeding.  For more information regarding the decision, please feel free to contact appellate counsel Joe Norman at jbnorman@liskow.com or Kathryn Gonski at kzgonski@liskow.com.

Fracking Scores with Two Colorado Supreme Court Opinions

Hydraulic fracturing, or “fracking,” is a hotly debated topic in many states.  In New York and Pennsylvania, anti-fracking groups have obtained a statewide ban on fracking and the allowance of local authority to regulate fracking, respectively.  Texas, however, has enacted a state law expressly preempting local authority over a number of drilling activities.  In March 2016, the Louisiana First Circuit recognized the preemptive authority of state law to regulate and permit fracking.  Now, the Colorado Supreme Court rendered two opinions on May 2, 2016 finding state law preempted local efforts to prohibit fracking.

The residents of Longmont, Colorado voted in 2012 to add Article XVI to the City’s home-rule charter.  The Article prohibited fracking and the storing or disposing of wastes created by fracking within the City’s limits.  The Colorado Oil and Gas Association sought a declaratory judgment invalidating and permanently enjoining the enforcement of the Article.  City of Longmont v. Colorado Oil and Gas Association, 2016 CO 29, ___ P. 3d ___ (Colo. 2016).  The Colorado Constitution recognizes the power of home-rule charters to supersede “any law of the state in conflict therewith.”  Colo. Const. art. XX, § 6.  However, the Colorado Supreme Court has consistently held that state law supersedes home-rule ordinances when they conflict on matters of either state concern or mixed local and state concern.  The Court concluded that the Longmont Article addressed a matter of mixed state and local concern and found the Article conflicted with and materially impeded the Colorado Oil and Gas Conservation Act.  Therefore, the Court held that state law preempted local attempts to regulate and prohibit fracking.  That same day, the Court made the same ruling with regard to a local moratorium on fracking enacted by the City of Fort Collins, Colorado.  City of Fort Collins v. Colo. Oil and Gas Ass’n, 16 CO 28 (Colo. 2016).  This moratorium, like the home-rule charter article, was preempted by the Colorado Oil and Gas Conservation Act.

The Colorado opinions echo the recent ruling of the Louisiana First Circuit.  In 2014, St. Tammany Parish filed suit after the announcement by Helis Oil & Gas of its intent to begin hydraulic fracturing in the Parish.  St. Tammany Parish Government v. James H. Welsh, 15-1152 (La. 1st Cir. App. Mar. 9, 2016).  The Parish filed suit against the state’s Commissioner of Conservation.  The Parish pointed to local ordinances zoning the proposed site as residential and also claimed the Commissioner’s permitting of the Helis project was unconstitutional.  The court agreed with the Parish that Article VI of the Louisiana Constitution bestows the land use and zoning power on the Parish but the court also recognized exceptions to this local power when the legislature’s clear and manifest purpose in enacting a law is to preempt the local ordinance.  The court recognized Louisiana Revised Statute § 30:28(F), which grants the Commissioner permitting power, as supreme over any other agency or political subdivisions’ attempt to prohibit or interfere with permitted drilling.  It further held that the State’s extensive legislation addressing every aspect of oil and gas exploration evidenced the legislature’s implied intent to preempt that area of law.  The Parish has requested review of the decision by the Louisiana Supreme Court.

These recent cases point out that the authority to regulate fracking varies from state to state and should be evaluated accordingly.

For further information, contact Catherine Napolitano at cnapolitano@liskow.com or Rob McNeal at rbmcneal@liskow.com.

Processor Required to Account For Diverted Volumes Used for Gas Lift

Generally, oil and gas production facilities have accounted for volume losses under the concept of “Fuel, Flare & Losses.” In a recent case, the Louisiana Fourth Circuit Court of Appeal held that processors must also account for gas volume diverted to gas lift operations.

In Red Willow Offshore, LLC v. Palm Energy Offshore, LLC, the Fourth Circuit found that a processing facility operator breached its Production Processing Agreement (“PPA”) with working interest owners by diverting without allocation the working interest owners’ production stream of natural gas to the operator’s own gas lift oil wells, and affirmed a trial court’s judgment awarding the working interest owners $1.16 million in damages for diversion of more than ten million cubic feet of gas.

Red Willow Offshore, LLC and Medco Energi US, LLC (collectively, “Red Willow”) were co-working interest owners of a natural gas well without the facilities to produce the well. Red Willow contracted a PPA with Palm Energy Offshore, LLC (“Palm”), the owner of a production processing facility and operator of its own wells, for transportation of Red Willow’s production stream to the Palm facility for commingling, processing, and preparation for sale. The PPA was silent as to the use of the Red Willow production stream as lift gas and made no mention of lift gas in the allocation provision, but required Palm to allocate to Red Willow its proportion of the metered volume of gas that exited the Palm facility for sale. However, before the Red Willow production stream reached the sales line, Palm diverted more than twenty percent of the gas to use as lift gas in its own low pressure oil wells. The gas lift operations often resulted in negative production; as one of Palm’s experts testified, “less came out than went in.”

Palm did not account for the diversion, did not compensate Red Willow for gas lost to the gas lift operations, and did not charge its own wells for use of the lift gas. Both the trial court and the Fourth Circuit determined that Palm’s unauthorized and unallocated use of Red Willow’s production stream was a breach of the PPA.

The Fourth Circuit found that the PPA required Palm to perform only processing services, and that it did not allow Palm to use Red Willow’s gas for the operational function of gas lift. The court found further that the allocation method set forth in the PPA accounted for volume losses due to fuel use, flaring, and shrinkage (often called a “Fuel, Flare & Losses” provision) but did not address adjustment for lift gas. The measurement provision did, however, expressly reference and adopt an American Petroleum Institute manual that requires that equitable allocation include adjustment for “fuel gas, gas lift, flare gas, and the like.” The court also considered state regulations and industry standards. Statewide Order No. 29-D-1, which adopted the API manual, requires an operator to provide reasonably accurate measurement and allow the owner to recover his just and equitable share of production. And the Gas Accounting Manual of the Council of Petroleum and Accountants Societies provides guidance on industry standards on gas accounting, and requires that a lease that uses lift gas from an outside source should be charged based on the price paid to the supplier.

The court found that “[u]ndoubtedly, these provisions require an operator to account for and properly allocate to its producers the value of the gas it uses as lift gas.”

Liskow and Lewis represented Red Willow. For more information regarding the decision, please contact Lauren Delery at ljdelery@liskow.com or Mark McNamara at mlmcnamara@liskow.com.

Derivatives: ISDA Announces 2016 New York Law Variation Margin Credit Support Annex

On April 14, 2016, the International Swaps and Derivatives Association, Inc. (ISDA) announced the 2016 ISDA Credit Support Annex for Variation Margin for use with New York law transactions (the 2016 CSA).

ISDA is in the process of updating certain of its documents to account for recent regulatory reforms.  The 2016 CSA introduces updates to the existing 1994 ISDA Credit Support Annex (the 1994 CSA) that will facilitate compliance with margining requirements for non-centrally cleared derivatives.  Parties to the 2016 CSA are able to negotiate collateral terms for variation margin in accordance with rules issued by U.S. prudential banking regulators[1], the U.S. Commodity Futures Trading Commission (the CFTC), and the European Union.

The fallout from the most recent financial crisis demonstrated a number of weaknesses in the OTC derivatives market.  In response, the G20 countries have been pursuing reforms to mitigate systemic risk posed by global OTC derivatives practices.  In 2011, the G20 countries requested that the Basel Committee on Banking Supervision and the International Organization of Securities Commissions (BCBS/IOSCO) jointly prepare minimum standards for margining requirements that would apply to non-centrally cleared derivatives.  BCBS/IOSCO published a final policy framework in 2015 (the BCBS/IOSCO Framework) requiring that market participants mitigate risk in OTC transactions by exchanging initial margin and variation margin.[2]  The statements of the BCBS/IOSCO Framework were not meant to be binding regulations, but rather key principles to guide national regulators in adopting margining rules that would apply in their respective jurisdictions.  Regulators in several jurisdictions, including the United States and the European Union, have since published margining rules for non-centrally cleared derivatives.[3]

Generally, the U.S. and EU rules require the collection or posting of initial margin and variation margin effective as of September 1, 2016 for the largest participants in the derivatives market.  Initial margin requirements for other market participants will be phased in over a four-year period while variation margin requirements for other market participants take effect as of March 1, 2017.  These regulatory initiatives dictated that the existing ISDA collateral documentation be revised.

For over 20 years, the existing 1994 CSA has been the preferred instrument for detailing credit support arrangements related to New York law ISDA contracts.  The 2016 CSA is the first attempt to update the credit support documentation and it contains notable revisions from the 1994 CSA.  While the 1994 CSA was intended to document both variation margin and initial margin requirements, the new 2016 CSA is intended to document only variation margin requirements.  Initial margin requirements are excluded from the 2016 CSA and, if applicable, would be addressed in a separate instrument.  Accordingly, the 2016 CSA provisions have been uniformly revised to account for only variation margin matters.  Other key revisions to the 2016 CSA include the following:

  • the scope is limited to “covered” transactions that are relevant for determining exposure under applicable rules;
  • the concept of a threshold for uncollateralized exposure is no longer relevant;
  • the timing for transfers of collateral delivery amounts has been shortened by one business day (timely demands require same day transfers);
  • the collateral eligibility standards incorporate regulatory compliance requirements;
  • collateral valuations include options for additional haircuts;
  • the dispute resolution procedures and exposure determinations account for a close-out amount structure under the 2002 ISDA Master Agreement;
  • the interest provisions include elections relating to interest payment mechanics and netting;
  • the interest provisions contemplate negative interest situations;
  • past due interest transfer payments incur default interest;
  • an obligation to transfer credit support under the 2016 CSA may be offset against an obligation to transfer credit support under other credit support annexes; and
  • the default remedies permit posted collateral held under the 2016 CSA to be offset against certain credit support under other credit support annexes.

Similar to the 1994 CSA, the 2016 CSA is an optional, bilateral form that contemplates both parties may be required to post credit support.  It consists of a pre-printed Annex which can be modified in a separately negotiated Paragraph 13.  And consistent with ISDA’s overall documentation architecture the 2016 CSA is a supplement to the Schedule to the ISDA Master Agreement for use with New York law transactions.  The 2016 CSA is available here.

ISDA is preparing an English law version of the credit support annex for variation margin, stand-alone credit support annexes for initial margin under New York and English law, and one or more protocols to amend existing contracts to comply with margining rules.  ISDA is also involved in recommending a singular methodology for calculating initial margin on non-centrally cleared derivatives called the Standard Initial Margin Model (SIMM).


If you have any questions regarding this Liskow & Lewis alert, please contact:

Nina Bianchi Skinner


[1] The U.S. prudential banking regulators are the Federal Deposit Insurance Corporation (FDIC), the Office of the Comptroller of the Currency, the Board of Governors of the Federal Reserve System, the Farm Credit Administration, and the Federal Housing Finance Agency.

[2] Click here to access the BCBS/IOSCO final framework entitled “Margin Requirements for Non-Centrally Cleared Derivatives” which was originally published in September 2013 and re-published in March 2015.  BCBS/IOSCO published the framework in consultation with the Working Group on Margining Requirements (WGMR) which was established in 2011 to develop a consistent global standard for margining requirements.  The WGMR is a collective effort by the Committee on Payment and Settlement Systems and the Committee on the Global Financial Systems.

[3] The U.S. prudential banking regulators issued final margining rules for non-centrally cleared derivatives in October 2015, click here to access the rules.  The CFTC issued final rules in December 2015, click here to access the rules.  The prudential regulators and CFTC have included margining exemptions for non-centrally cleared derivatives executed with counterparties that are exempt from Dodd-Frank’s mandatory clearing requirements.  In the coming months, the U.S. Securities and Exchange Commission will issue a separate set of final rules for entities subject to its jurisdiction.  In March 2016, EU regulators published final draft regulatory technical standards (RTS) for the collateralization of non-centrally cleared derivatives under the European Market Infrastructure Regulation (EMIR), click here to access the rules.  The final draft RTS have been submitted to the European Commission for approval.


Louisiana Appellate Court Unanimously Dismisses Cross-Appeals in Legacy Case

Louisiana appellate court unanimously dismisses cross-appeals in legacy case, finding that the trial court improperly designated partial summary judgment rulings as final under Article 1915 of the Louisiana Code of Civil Procedure.

            In Spanish Lake Restoration, LLC v. Shell Oil Company, et al., the Louisiana First Circuit Court of Appeal recently dismissed cross-appeals taken in a legacy case.  The legacy plaintiff (“Spanish Lake”) and Shell Oil Company (“Shell”) appealed a judgment that granted, in part, and denied, in part, motions for summary judgment filed by Shell.  The judgment granted Shell’s motion to dismiss Spanish Lake’s claims against Shell pursuant to the subsequent purchaser doctrine, but reserved to Spanish Lake the right to plead and possibly develop two alternative statutory theories asserted as a basis for relief.  The court further denied Shell’s motion to the extent it argued that Spanish Lake’s claims were prescribed.  The trial court included in the judgment that “there is no just reason for delay in designating this judgment as a partial final judgment pursuant to 1915(B)(1) of the Louisiana Code of Civil Procedure,” and noted that the parties expressly agreed to this designation.

            Spanish Lake appealed the judgment in Shell’s favor dismissing its claims based on the subsequent purchaser doctrine.  Shell then cross-appealed the trial court’s reservation to Spanish Lake of a possible right to attempt to articulate or develop claims under statutory theories, as well as the trial court’s prescription ruling.  The First Circuit declined to reach the merits of any of these issues, finding instead that it lacked appellate jurisdiction because the appeals were taken from a partial judgment that was improperly designated as final under article 1915(B).  The court first explicitly rejected the notion that appellate jurisdiction can be conferred simply by agreement of the parties.  Rather, the trial court must conduct its own inquiry as to whether the designation was proper.  Since the trial court did not provide any reasons for its designation, the Court of Appeal was required to conduct a de novo review of the final judgment designation.  Pursuant to that review, the court held that the designation was improper because:  (i) Article 1915 does not allow for denials of motions for summary judgment to be designated as final judgments; and (ii) the factors to be considered in determining whether “there is no reason for just delay” (as set forth in R.J. Messinger, Inc. v. Rosenblum, 2004-1664 (La. 3/2/05), 894 So. 2d 1113) were not met.  The court additionally recognized—but declined to exercise—its discretion to convert the appeals to applications for supervisory writs, which would have allowed it to rule on the merits of the issues before it.

            The Spanish Lake decision demonstrates that neither the agreement of the parties, nor the trial court’s bare designation of a partial judgment as final is necessarily sufficient to confer appellate jurisdiction over a judgment that is not immediately appealable.  Rather, the appellate courts may take a harder look at whether such a designation is truly warranted, with the potential consequence of the appeal being ultimately dismissed for lack of jurisdiction.  Indeed, a similar decision was recently rendered by the Louisiana Fifth Circuit Court of Appeal in Bank of New York v. Holden, 15-466 (La. App. 5 Cir. 12/23/15), 182 So. 3d 1206.

               A copy of the First Circuit’s decision can be found here.  For more information regarding the decision, please contact George Arceneaux at garceneaux@liskow.com or Kelly Becker at kbbecker@liskow.com.

“Production in Paying Quantities”: Louisiana Appellate Court Decides When and What Should be Considered in Determination

The Louisiana Second Circuit Court of Appeal, in Middleton, et al. v. EP Energy E&P Company, L.P., et al., concluded that, in considering whether mineral leases terminated for failure to produce in paying quantities, a fact finder may consider periods of production years prior to filing suit, but must consider all factors which would influence a reasonably prudent operator to continue production, and at the summary judgment stage, cannot simply emphasize certain relevant evidence and disregard other evidence in this determination.  In doing so, the Second Circuit affirmed in part and reversed in part the lower court’s ruling granting a motion for partial summary judgment in favor of plaintiffs-lessors terminating three mineral leases for failure to produce in paying quantities, and remanded to the district court for further proceedings.

In Middleton, plaintiffs, the successors to the original lessors, filed suit against defendants-oil and gas companies who had an interest in maintaining the three mineral leases, arguing that the three leases terminated on their own terms for failure to produce in paying quantities during a period of forty-one months approximately 17 years prior to filing suit.  The lower court agreed with the plaintiffs, finding that, even if it were to consider the profit calculations put forth by the defendants, the unitized well holding the leases averaged a profit of just over $70 a month, and this minimal profit was not “sufficient to induce a reasonably prudent operator to continue production.”  The lower court thus granted the plaintiffs’ motion for partial summary judgment, and ordered that the leases terminated by their own terms during this 41-month period.

On appeal to the Second Circuit, the defendants argued the lower court erred in considering a period of production that occurred 17 years prior to the filing of plaintiffs’ suit and in ignoring the following 17 years of production.  The Second Circuit rejected that argument, finding prior authority under Louisiana law that considered periods of production years prior to filing suit supported the plaintiffs’ position, and concluding that defendants had not shown that the lower court was required to consider the well’s production in the subsequent 17 years.

The Second Circuit next turned to defendants’ second argument: the lower court erred in finding the unitized well failed to produce in paying quantities as the evidence demonstrated that a reasonably prudent operator would have continued production.  The appellate court noted that it was the plaintiffs’/lessors’ burden of demonstrating cancellation of the leases, and recognized that the standard to be applied in determining whether the well produced in paying quantities is “whether or not under all the relevant circumstances a reasonably prudent operator would, for the purpose of making a profit, continue to operate a well in the manner in which the well in question was operated.”   The Second Circuit also recognized that the term “paying quantities” implies that production income exceeds operating expenses.

Turning to the evidence presented by both plaintiffs and defendants, the appellate court noted that although the plaintiffs introduced evidence that expenses exceeded revenue during the time period at issue, defendants had produced the affidavit of a petroleum engineer who testified to the following: (1) the expenses included extraordinary expenses; (2) the average monthly profit excluding these extraordinary expenses was over $70; and (3) because a workover increased production, an operator could reasonably assume that the extraordinary expenses incurred during the workover could be recouped from continued production.   The appellate court first noted that extraordinary, nonrecurring expenses should not be considered in a determination of production in paying quantities, and also found that the lower court had improperly disregarded evidence demonstrating another well in the same formation was producing successfully and that the well at issue had increased production.  The Second Circuit concluded that defendants’ evidence was sufficient to create a material issue of fact, after considering all factors which would influence a reasonably prudent operator to continue production, including the market price available, the relative profitability of other nearby wells, the operating costs, the net income, and the reasonableness of the expectation of profit.  The court thus reversed the part of the judgment granting the plaintiffs’ motion for partial summary judgment and terminating the mineral leases.

The Middleton decision indicates that in determining whether a lease terminated for failure to produce in paying quantities, the factfinder may consider production periods even years prior to the filing of suit, and is not required to consider subsequent years of production.  Moreover, the decision demonstrates that the factfinder must consider all relevant evidence – not just profit realized, and must not, at least at the summary judgment stage, give more weight to certain evidence.   A copy of the Second Circuit’s decision can be found here.  For more information regarding the decision, please contact Rob McNeal at rbmcneal@liskow.com or Erin Bambrick at ebambrick@liskow.com.

Sixth Circuit Will Not Rehear Venue Question in Clean Water Act Rule Dispute

On April 21, 2016 the United States Court of Appeals for the Sixth Circuit denied several petitions for rehearing en banc a Sixth Circuit panel decision that looked at which courts (federal district court or federal courts of appeal) have original jurisdiction to hear challenges to the EPA’s Clean Water Rule.  This recent ruling leaves in place the Sixth Circuit panel ruling holding that jurisdiction lies at the appeals court level.

EPA’s Clean Water Rule has already sparked a long and complicated history of litigation.  As a refresher, here are some of the highlights:

  • June 29, 2015: EPA publishes final “Clean Water Rule” setting out a new definition of “Waters of the United States.” 80 Fed. Reg. 37054 (Jun. 29, 2015).  Soon after, multiple petitions are filed challenging the rule in federal district courts and in federal circuit courts.
  • July 28, 2015: The Judicial Panel on Multidistrict Litigation consolidates the pending circuit court actions in the Sixth Circuit Court of Appeals.
  • August 27, 2015: The federal District Court for the District of North Dakota concludes that jurisdiction is proper in the district courts and enjoins enforcement of the Clean Water Rule in the 13 States that are parties to the lawsuit in front of the court.
  • October 9, 2015: The Sixth Circuit Court of Appeals issues a nationwide stay of the Clean Water Rule. In Re: Environmental Protection Agency and Dep’t of Defense Final Rule “Clean Water Rule”, Nos. 15-3799/3822/3853/3877, 803 F.3d 804 (6th Cir. 2015).
  • February 22, 2016: A three-judge panel of the Sixth Circuit Court of Appeals holds that the circuit courts have jurisdiction to hear the challenges to the Clean Water Rule.
  • March 3rd, 2016: The Federal defendants file a Motion to Dismiss the North Dakota District Court case in light of the Sixth Circuit’s decision from February 22nd.
  • March -April 2016: Several Parties file petitions to the Sixth Circuit for rehearing en banc the panel decision on jurisdiction from February 22nd.
  • April 21, 2016: The Sixth Circuit denies the en banc petitions, leaving the February 22nd decision in place.

We will have to wait and see if the States and industry groups challenging jurisdiction in the Sixth Circuit will appeal to the U.S. Supreme Court.  Meanwhile, there are still parallel proceedings questioning jurisdiction at the North Dakota district court and the Eleventh Circuit (on appeal from the District Court for the Southern District of Georgia).  The Sixth Circuit’s denial of rehearing makes it more likely that the Clean Water Rule will ultimately be reviewed in the circuit courts, specifically, the Sixth Circuit.  However, the order has no immediate substantive effect on the regulated community because it leaves in place the nationwide stay of the Clean Water Rule.

Failure to Timely Pay Texas Ad Valorem Taxes: Reminders for Taxpayers and Secured Lenders

The extended downturn in the oilfield economy is showing up in some taxpayers’ inability to pay their Texas real property and personal property ad valorem taxes when those taxes become due.  This note reminds taxpayers what happens when the ad valorem taxes are not timely paid.  It also reminds lenders with security interests in real and personal property to monitor their borrowers’ financial situations and any related developments in tax liens and tax sales in order to maximize the value of collateral.

The Texas Tax Code provides that a tax lien attaches to all taxable real property and personal property located in Texas on January 1 of each tax year for that tax year’s ad valorem taxes due the taxing jurisdiction.  The lien attaches automatically – the taxing jurisdiction need do nothing further to perfect the tax lien.  And here is the catch – the tax lien takes priority over the lien of a secured lender who perfected its lien when the loan was made, even though the loan was made and the security interest in the collateral was perfected well before the ad valorem taxes subject to the tax lien become due.

If the taxpayer who owns the taxable property fails to pay the ad valorem tax due within the period prescribed by Texas law, the tax due becomes delinquent.  Delinquent taxes incur penalties and interest, so the amount due the taxing jurisdiction quickly can increase.  If the delinquent taxes, penalties and interest are not paid, the taxing jurisdiction can institute a suit to collect the amounts due and foreclose upon the tax lien.  Under certain circumstances, taxing jurisdictions can have real property and personal property of the taxpayer seized under a tax warrant for the failure to timely pay the ad valorem taxes due.  Once a tax foreclosure or a seizure occurs, the taxing jurisdiction then can move to have that property sold at a tax sale for payment of the ad valorem taxes, penalties and interest due.

The Texas Tax Code sets out the procedures to be followed by the taxing jurisdiction in moving forward with the tax sale.  The Texas Tax Code also sets out how the proceeds of the tax sale are distributed, but because the tax lien takes priority over the lender’s security interest, the taxing jurisdiction is entitled to be paid the amount due out of the proceeds before a secured lender is paid anything.  And, in fact, if a purchaser knows the property to be sold at the tax sale has a lender’s lien on it, the purchaser will be inclined to limit the amount of its bid to the taxes, penalties and interest due.

Purchasers of property acquired at a tax sale in Texas take title subject to a right of redemption of the taxpayer whose property was sold.  The limited period during which the right of redemption must be exercised varies depending on the type and use of the property in question.  But the right of redemption belongs to the taxpayer whose property was sold – the lender with a security interest in the property sold at the tax sale does not have a right of redemption and cannot exercise the right on behalf of its borrower.  The lender’s security interest is not extinguished in the tax sale, but the lender may or may not have any business relationship with the purchaser of the property sold at the tax sale and thus may have limited control over the use to which the purchased property is put and how that property is maintained.

Taxpayers need to remember that they have a limited period of time in which to exercise their right of redemption for property sold at a tax sale, assuming that they can raise the amounts necessary to redeem.  Lenders with secured interests in property need to monitor closely the financial condition of each of their borrowers, including ensuring that their ad valorem tax payments are timely made.  Most importantly, lenders need to understand that if a borrower’s ad valorem tax payments are not timely made, the tax jurisdiction may move to effect a tax sale of their borrower’s collateral.  Depending on the nature of the collateral, lenders may consider whether they can stop the tax sale by assisting their borrower in making the payment of ad valorem tax amounts due.  Lenders also may consider whether they should bid at the tax sale in order to acquire the collateral and preserve its value through the lender’s subsequent foreclosure sale to a credible purchaser.  Alternatively, lenders may consider working with the borrower to have the borrower exercise its right of redemption, and then foreclose on the collateral.  Following either of these approaches may aid the lender in maximizing the value of the collateral and enhancing the lender’s chances on full repayment of the loan.

Liskow & Lewis can help taxpayers and lenders determine their respective courses of action when ad valorem taxes have not been timely paid.  For questions, contact John Bradford at (713) 651-2984.


Sea Change: New BOEM Proposed Rule Signals Major Shift in How Air Emissions Would Be Regulated in the OCS

In the next few days, the Bureau of Ocean Energy Management (BOEM) will publish in the Federal Register a Proposed Rule that would result in a significant change on how the agency regulates air emissions from oil and gas operations on the Outer Continental Shelf (OCS), in the Central and Western Gulf of Mexico (GOM).  On March 17, BOEM released a pre-publication version on their website.  With the title of “Air Quality Control, Reporting, and Compliance,” the 349-page document details what would be the first major re-write of the OCS air quality regulations in 35 years.

From a high-level standpoint, the agency’s approach would stay the same (as required by the OCSLA): projected emissions would be compared to exemption thresholds, and if these are exceeded, additional analysis would be required to determine if emissions “significantly affect the air quality of any state.”  43 U.S.C. § 1334(a)(8).  The proposed rule does not change the exemption thresholds at this time, although the agency all but assures regulated entities that the exemption thresholds will be changed in the near future.[1]  However, the proposed rule modifies to some degree or another every other aspect of the current air regulations.

Under the proposed rule, lessees and operators submitting a new or revised Exploration Plan, Development and Production Plan, or Development Operations Coordination Document, would calculate the projected emissions associated with the plan just like they have to do under the current rule.  However, the projected emissions would now include additional pollutants to account for all criteria pollutants and precursors.  The projected emissions would also have to include emissions from mobile support craft operating in support of the facility, regardless of their distance from the facility.  Finally, contemporaneous emissions from facilities that are wholly or partially owned, controlled, or operated by the same entity would need to be aggregated if the facilities are within 1 nautical mile or relate to a common reservoir.  The projected emissions would be compared to the exemption thresholds based on the existing formulas that have Distance as the only variable.[2]  However, once new exemption threshold values are promulgated, the Distance to use would be the State Seaward Boundary instead of the ”from the closest onshore area.”  30 C.F.R. § 550.303(d).

If VOC emissions exceed the threshold, Emission Reducing Measures (ERM) are automatically required based on the type of facility and attainment status of the nearest State.  For all other pollutants, modeling would be required.  The proposed rule modifies the points of origin and points of impact for modeling analysis, requiring lessees to evaluate impacts over the entire area of a State’s jurisdiction extending to its seaward boundary, and model non-stationary emission points from a separate point of origin.  In addition, the proposed rule would now harmonize the air standards for determining impacts with the EPA standards.  Finally, the impacts analysis in attainment areas would need to take into account other onshore and offshore sources that may already be using the maximum allowed increases in ambient air concentration.

If the modeling analysis shows that the applicable standard or benchmark would be exceeded at the State water line, ERM’s would be required.  While the current rule uses Best Available Control Technology (BACT) as the first and primary control mechanism (and to a lesser degree, emission credits), the proposed rule would allow use of other mechanisms to reduce emissions.  As such, BACT is but one type of ERM, along with emissions credits, operational controls and equipment replacement.  Lessees would be required to identify all technically feasible ERM’s and rank them according to potential effectiveness.  Lessees would be required to implement the most effective one unless it is found not to be cost effective.  Whether consideration of BACT must be included in this ERM analysis depends on the pollutant and the attainment status.  However, BOEM stresses that BACT as defined in the BOEM rule “would not have the same meaning as used in the USEPA regulation.”  Proposed Rule, p. 108.

Reporting and recordkeeping requirements would be expanded under the proposed rule.  All facilities would need to record fuel usage and activity data, which would be submitted to BOEM periodically.  Facilities that are subject to emission controls or have large emissions may also be subject to monitoring requirements using PEMS.

The proposed rule would require resubmittal of plans 10 years after approval, and they would be subject to the air control requirements in place at that time.  In addition, after issuance of new exemption thresholds, plans that were previously approved would need to be resubmitted for compliance with these changes (resubmittal depends on the date of approval and would begin in the year 2020).

In the proposed rule, the agency solicits comments on many specific issues and requirements.  Comments will be due 60 days after publication in the Federal Register, but industry is expected to ask for an extension.  While environmental groups can be expected to support these changes, industry groups such as API have already expressed deep concerns about the proposal.  Lessees and operators should review the proposed rule and provide comments prior to the deadline.

[1]              Although the thresholds are not changing at this time, BOEM is currently conducting a scientific study to determine if they should be changed.  Any new exemption thresholds are expected to be finalized no later than the year 2020.  Proposed Rule, p. 80.

[2]              For example, for TSP, SO2, NOX and VOC, the emission exemption threshold (E) in tons per year is equal to 33.3 x D, where D is the distance in miles to the closest State shoreline.  Therefore, a facility located 50 miles from shore would have an exemption threshold of 1,665 TPY.