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.

New Developments in the Determination of the Texas Franchise Tax Liability

The Texas Franchise Tax is imposed on taxable entities that do business in Texas or that are chartered or organized in the state.  Taxpayers subject to the Texas Franchise Tax may compute their tax liabilities under several alternative methods to determine which one results in the lowest amount of tax due.

One such method is to start with the total revenue from the entire business and subtract from that amount either a deduction for the taxpayer’s cost of goods sold (“COGS”) or a deduction for the compensation the taxpayer pays to its officers, directors, owners, partners and employees in determining taxable margin and the resulting tax liability.   A Texas appellate court decision last week may have made the deduction for COGS more valuable to taxpayers liable for Texas Franchise Tax.

In a Memorandum Opinion filed on March 9, 2016, the Texas Court of Appeals for the Third District (Austin, TX) affirmed the trial court’s decision that CGG Veritas Services (U.S.), Inc. ( “CGG Veritas”) was entitled to include its costs of labor and materials incurred to acquire and process seismic data for its clients in its deduction of COGS for Texas Franchise Tax purposes.  Hegar v. CGG Veritas Services (U.S.), Inc., No. 03-14-00713-CV (Mar. 9, 2016).   In computing its Texas Franchise Tax liability, CGG Veritas made the determination that deducting its COGS would provide a larger benefit than deducting its compensation paid.  Included in its COGS deduction were the costs of labor and materials incurred to acquire and process seismic data that it sold to clients who used the data to determine where to drill oil and gas wells.  CGG Veritas took the position that these costs were furnished “to a project for the construction, improvement . . . of real property” for purposes of Tex. Tax Code § 171.1012(i) and, pursuant to that section, it was entitled to include those costs in the computation of its COGS deduction.  Important to this position was that an oil and gas well was “real property” and that the drilling of such a well was a project for the construction of real property.  The State, on audit, at the trial court, and on appeal argued that CGG Veritas was a service provider who could not include the disputed costs in its deduction for COGS.

The appeals court applied its interpretation of the meaning of the term “labor” previously stated in Combs v. Newpark Resources, Inc., 422 S.W. 3d 46 (Tex. App. – Austin 2013) and concluded that the Texas legislature intended that entities subject to the Texas Franchise Tax could deduct a wide range of labor expenses, even those that might be described “services”, pursuant to section 171.1012(i).  According to the court, the test for whether a labor or material cost is includible in the COGS deduction in this context is whether the activity is an “essential and direct” component of the project for the construction of real property.

The appeals court then reviewed the findings of the trial court on this issue and found evidentiary support for the trial court’s determination that CGG Veritas’ costs for seismic data acquisition and processing activities were an integral, essential and direct component of the drilling process, a process clearly “a project for the construction of real property”.  Accordingly, the appeals court affirmed the trial court’s judgment in favor of CGG Veritas.

The decision in CGG Veritas Services (U.S.), Inc. indicates that “labor and materials for a project for the construction or improvement of real property” will be broadly interpreted for purposes of the Texas Franchise Tax COGS deduction.  The decision is important for other oilfield services companies who now also may find that a COGS deduction is preferable to a compensation deduction in determining taxable margin and the resulting tax liability.

The decision also has implications for taxpayers outside of the oilfield business who produce and sell or license intellectual property to customers for the construction or improvement of real property.  These latter taxpayers may find like CGG Veritas that the sum of (a) essential and direct labor and materials incurred for a project for the construction or improvement of real property and (b) all other costs that properly are includible in COGS will exceed the compensation deduction in arriving at taxable margin for Texas Franchise Tax purposes. Liskow & Lewis can help in this determination.

Production in Paying Quantities: Second Circuit Holds Lower Courts Must Consider All Relevant Factors, Not Just Profit

Since this blog’s post on production in paying quantities on January 26, 2016, the Louisiana Second Circuit Court of Appeal rendered its latest decision on the subject in Middleton v. EP Energy E&P Co., L.P., 50,300-CA (La. App. 2d Cir. 2/3/16).  While not particularly groundbreaking, Middleton does provide further guidance to mineral lessees and litigators with respect to the relevant factors and time period considered in a paying quantities case.  Specifically, courts must consider all relevant factors, not just profit, when determining whether production is in paying quantities.

The Middleton plaintiffs filed suit in 2013 claiming that three mineral leases maintained by a unit well had terminated because the well failed to produce in paying quantities for a 41-month period from August 1991 to December 1994.  After discovery, the plaintiffs filed a motion for summary judgment asserting the leases had terminated because well expenses exceeded revenue by $56,477.55 for the 41-month period.  Defendants filed cross motions for summary judgment asserting that the well actually made a profit of $2,905.96 over the 41 months, an average of $70.87 per month.  The district court granted the plaintiffs’ motion finding that the 41-month period of production proposed by the plaintiffs was “consistent with the jurisprudence” and that, even adopting the defendants’ calculations, “operating a well at a loss or minimal profit for 41 months is not sufficient to induce a reasonably prudent operator to continue production.”

On appeal, the Second Circuit first addressed the defendants’ argument that the plaintiffs should be prohibited from alleging failure of production in paying quantities for a time period that occurred nearly 20 years before suit was filed.  The appellate court rejected this argument observing that the Louisiana Third Circuit in Lege v. Lea Exploration Co., Inc. 631 So. 2d 716 (La. App. 3d Cir. 1994) considered a production period that occurred seven to ten years before the date of trial.  The court also, unsurprisingly, rejected defendants’ argument that the court was required to consider production during the 17 years following the 41-month period.

Ultimately, the Second Circuit reversed the district court’s judgment on other grounds.  First, the court recognized that the plaintiffs’ calculation of expenses included extraordinary expenses for the installation of a compressor and workover operations and instructed that “such nonrecurring expenses are not considered as operating expenses for the purpose of determining production in paying quantities.”  When these expenses were deducted from the well costs, the well made an average monthly profit of $70.87 during the 41-month period.

The court then explained that, although the district court found the $70.87 monthly profit insufficient, the determination of paying quantities is a fact-intensive inquiry that requires the consideration of various factors in addition to profit.  The court further instructed that the fact finder must consider:

“all matters which would influence a reasonable and prudent operator. The factors that the court should consider include the depletion of the reservoir, the price at which the product can be sold, the relative profitability of other wells in the area, the operating costs of the lease and the net profit.”

Consequently, the court ruled that the district court exceeded its role at the summary judgment stage and held that a genuine issue of material fact existed on the paying quantities issue.

Again, although Middleton does not break new ground on the subject of paying quantities, there are some important takeaways.  Firstly, the decision reaffirms that extraordinary, nonrecurring expenses are not operating expenses.  Secondly, the court accepted the plaintiffs’ 41-month period as the relevant time period for determining whether production was in paying quantities.  Previous cases have considered far shorter time periods – from a minimum of eight to a maximum of eighteen months, so it is not surprising that the court accepted a longer period proposed, in this instance, by the landowner-plaintiffs because longer periods ordinarily favor the operator in paying quantities determinations.  Finally, and most importantly, Middleton holds that a fact finder may not base its determination of production in paying quantities on profit alone.  Instead, the court reiterated that the fact finder must consider “all of the 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,” and, according to the earlier enumeration of factors in the opinion, “the depletion of the reservoir.”

Note:  The Middleton plaintiffs have filed an application for rehearing with the Second Circuit, and the court’s decision on February 3, 2016, is not yet final.


EPA Proposes Significant Changes to the RMP Rule

On February 25, 2016, the EPA proposed revisions to its Risk Management Program (RMP) rule.  Click here to see the proposed rule.  The rule revisions are required by Executive Order 13650, which called for additional improvements on chemical facility safety and security.  Click here to see Executive Order 13650.  While the proposed rule does not change the applicability thresholds, it does include significant changes to the current requirements.

  • Incident Investigations: All facilities with a Program 2 or 3 process[1] would be required to conduct a Root Cause Analysis (RCA) as part of the incident investigation after a “catastrophic release” or a near-miss.  The proposal would change the current “imminent and substantial endangerment” definition of “catastrophic release” to “a major uncontrolled emission, fire, or explosion, involving one or more regulated substances that results in deaths, injuries, or significant property damage on-site, or known offsite deaths, injuries, evacuations, sheltering in place, property damage, or environmental damage.”  Proposed Rule, p. 31.  Current regulations only require that the incident investigation identify the “factors that contributed to the incident,” language that the agency believes has resulted in missed opportunities to fix systemic root causes after incidents and near misses.
  • Third-Party compliance audits: EPA is proposing to require independent third-party compliance audits after an RMP-reportable accident or agency findings of significant noncompliance with the RMP rule at a Program 2 or 3 facility.  The final audit report must be submitted to the agency, and it must include any adjustments made by the auditor to any draft reports provided to the owner or operator for their review or comment.  The rule prohibits claiming the audit report and related records as attorney-client communications or attorney work-product even if the auditors are managed by attorneys.
  • Safer Technology and Alternatives Analysis: EPA is mandating consideration of potentially safer technology and alternatives as part of the RMP-required PHA for Program 3 processes in the following industries: petroleum and coal products manufacturing, chemical manufacturing, and paper manufacturing.  The consideration has to include, in order of preference, Inherently Safer Technology (IST) or Inherently Safer Design (ISD), passive measures, active measures, and procedural measures.[2]  A feasibility analysis would be required for any IST or ISD considered.[3]
  • Emergency Response Program Coordination with Local Responders: The proposal clarifies the difference in emergency response requirements applicable to responding facilities (facilities that use their own employees/resources to respond to an emergency) and non-responding facilities (facilities that rely on local responders).  EPA would also require facilities to meet with local responders at least annually to coordinate emergency response needs and responsibilities.
  • Facility Exercises: The rule would require Program 2 and 3 facilities, whether they are responding facilities or non-responding facilities, to conduct notification exercises annually.  Responding facilities would also have to conduct field and tabletop exercises, at least every 5 years for the former and annually for the latter (except during the year that a field exercise occurs).  The owner or operator would be required to prepare an exercise report, which would be provided to local responders and made available to the public.
  • Information availability: Under the proposal, RMP facilities would now be required to provide certain information beyond the Risk Management Plan itself to local emergency responders and LEPCs upon request.  The agency also proposes that more information be made available to the general public.  However, some information would still be off-limits, such as Offsite Consequences Analysis and confidential business information.  Finally, owners and operators of a facility that has an RMP reportable accident would be required to conduct a public meeting within 30 days of the accident.

There are indications in the proposed rule that EPA may not be done with RMP revisions.  In addition, OSHA is expected to issue revisions to its own PSM rules in response to Executive Order 13650.  Click here to see OSHA’s Request for Information.  Therefore, owners and operators should review their current compliance programs for both RMP and PSM to ensure they are well-positioned for future changes. This is especially true given that EPA recently added “Reducing Risks of Accidental Releases at Industrial and Chemical Facilities” as a new National Enforcement Initiative starting on October 1, 2016.

The RMP proposal is expected to garner a lot of attention from both industry and Non-Governmental Organizations.  According to EPA, the 2014 Request for Information on RMP revisions received 579 public comments plus 99,713 letters and signatures from various mass mail campaigns.  See Docket ID. EPA-HQ-OEM-2014-0328-0001.  The RFI responses already show that industry is concerned about investigation of near misses and regulation of IST/ISD.  Owners and operators should review the proposed rule and offer comments before the deadline.  Comments on the RMP Proposed Rule will be due 60 days after publication in the Federal Register.

[1] An activity involving RMP-regulated substances is eligible for Program 1 requirements if it has not had an accidental release with offsite impacts in the last five years and would not affect the public in the case of a worst-case release.  Program 3 requirements apply to a process that (1) does not meet Program 1 requirements, and (2) is subject to the OSHA PSM rule or classified as one of ten specified NAICS codes.  Processes not eligible for Program 1 or 3 have to meet Program 2 requirements.

[2] The rule would define “inherently safer technology or design” as “risk management measures that minimize the use of regulated substances, substitute less hazardous substances, moderate the use of regulated substances, or simplify covered processes in order to make accidental releases less likely, or the impacts of such releases less severe.”  Proposed Rule, p. 213.

[3] For an agency primer on safer technology and alternatives, see http://www.epa.gov/rmp/chemical-safety-alert-safer-technology-and-alternatives.

Clean Power Plan: The Legal Battle Continues

The group of petitioners challenging the EPA rules imposing strict limits on carbon dioxide emissions from existing power plants filed its opening briefs on Friday, February 19.  The lawsuit, West Virginia v. EPA (D.C. Cir. No. 15-1363) is unusual because of its sheer volume.  Petitioners include thirty States, State agencies, and local government entities and more than one hundred private companies, cooperatives, and industry trade groups.  The Clean Power Plan would affect every electricity user in the United States, from the largest manufacturing plant to the smallest home.

The petitioners filed two briefs:  one addressing “core legal issues” and the other addressing “procedural and record issues.”  Arguments in the “core legal issues” brief include:

  • The Clean Air Act does not authorize EPA to make such sweeping changes to how electricity is generated and transmitted in the United States.
  • EPA cannot require electricity generation to be shifted from coal-burning units to units that use natural gas or renewable energy sources without a clear statement from Congress.
  • EPA also cannot require electricity generation to be shifted from coal-burning units to units that use other energy sources as a pollution control technology.
  • The Clean Power Plan usurps authority given to States by the U.S. Constitution and the Clean Air Act.

In the “procedural and record issues” brief, arguments include:

  • The Clean Power Plan final rule is so different from the proposed rule that it violates fundamental administrative law principles.
  • The Rule’s strategies for limiting carbon dioxide emissions are not what the Clean Air Act requires.
  • The Rule arbitrarily excludes pre-2013 low- and zero-emitting generation sources from being able to create emission reduction credits.
  • The Rule includes provisions that EPA did not fully consider before issuing the Rule.

On February 9, 2016, the Supreme Court ordered that the Clean Power Plan Rule could not take effect until all of the legal challenges to it have been resolved – including a challenge in the Supreme Court, if that were to happen.  This Order indicates that the Supreme Court believes that the Petitioners have a reasonable chance of winning the challenge in the U.S. Court of Appeals for the D.C. Circuit.  The Supreme Court’s action, crucially, prevented State governments from having to spend the next couple of years developing plans to fulfill the Clean Power Plan’s complex requirements.

The case is moving quickly.  EPA’s responding brief is due on March 28, and all briefs have to be filed by April 15.  The D.C. Circuit will hear oral arguments on June 2 (and 3, if necessary).  This schedule means that the D.C. Circuit may rule in the Fall or Winter of 2016.  We will continue to provide updates as the case goes on.

Click here for the Supreme Court’s Order.

Act 312: Federal Court Holds That Plaintiff Cannot Pocket “Additional Remediation Damages” Without Express Contractual Provision

On February 1, 2016, a federal district court issued a ruling in Moore v. Denbury, — F.3d — (W.D. La. 2016), with important implications for “legacy” lawsuits in Louisiana.  The court interpreted the 2014 amendments to Act 312 (La. R.S. § 30:29) to hold that “a plaintiff cannot directly recover additional remediation damages in the absence of an express contractual provision.”  Instead, these additional remediation costs in excess of the amount needed to remediate the property to the requisite state standards must be paid into the registry of the court and used for remediation.

Following the enactment of Act 312, legacy plaintiffs profited from the “delta” between the amount necessary to remediate contaminated property to regulatory standards—which must be paid into the registry of the court, and damages for “additional remediation” above regulatory standards (most frequently to “original condition”)—which were paid to plaintiffs.  In interpreting a prior version of Act 312, the Louisiana Supreme Court explained in State v. La. Land and Exploration Co., 110 So. 3d 1038 (La. 1/30/13) (“LL&E”), that legacy plaintiffs are entitled to additional remediation damages in two circumstances: (1) if required by an express contractual provision, or (2) if the mineral lessee has acted unreasonably or excessively under the lease.

The Moore plaintiffs sought original condition restoration under the second category, alleging that Denbury had operated unreasonably and excessively.  In response to a motion for summary judgment filed by Denbury on its obligations, the court made an Erie determination as to the effects of post-LL&E amendments to Act 312.

The court methodically walked through the current version of Act 312 noting that: (i) under Subsection (D), all damages awarded for the evaluation or remediation of environmental damages shall be paid exclusively into the court registry except as provided in Subsection (H); (ii) Subsection (H) provides that any award for “additional remediation” in excess of the cost of the feasible plan is not required to be paid into the court registry, and (iii) Subsection (M)(b) further provides that damages for “additional remediation” are allowed only if an express contractual provision provides for them.

Specifically, Subsection (M), enacted in 2014, allows damages awards only for

(a) The cost of funding the feasible plan adopted by the court.

(b) The cost of additional remediation only if required by an express contractual provision providing for remediation to original condition or to some other specific remediation standard.

(c) The cost of evaluating, correcting or repairing environmental damage upon a showing that such damage was caused by unreasonable or excessive operations…

(d) The cost of nonremediation damages.

Id. at § M(1) (emphasis added).

The court concluded that because Subsection M uses the term “additional remediation”—but only in M(b)—only damages for “additional remediation” pursuant to an express contractual provision are exempt from deposit into the court’s registry.  The court observed that “the Legislature could have easily placed ‘additional remediation’ in Subsection M(c) in connection with unreasonable or excessive operations.  It did not.”  Moore, p. 12-13.  The court also found the timing of the amendments “immediately after the Supreme Court’s decision in LL&E” to be meaningful: “Had the Legislature desired the status quo, it would not have needed to alter the legislation.”  Id. at p. 14.

Denbury’s motion for summary judgment was denied to the extent it urged that additional remediation damages based on excessive operations were not available at all, since “depending on the facts uncovered at trial, it may have a duty to repair damage caused as a result of its alleged unreasonableness or excessiveness.  However, these damages would not go to the Moores directly; rather, Denbury would deposit them into the Court’s registry.”  Id. at p. 16.

If the rationale of Moore is adopted by Louisiana courts, the “additional remediation damages–damages that plaintiffs can pocket” (Id. at p. 3) should be limited to those cases in which a landowner has an express contract-based claim for additional remediation.  Although defendants who have operated “unreasonably or excessively” may still be compelled to pay such damages, plaintiffs cannot access them.