The Energy Law Blog

The Energy Law Blog

Oil & gas exploration, developmnet, & marketing in the gulf coast

Texas Supreme Court Holds Producer Not Required to Share in Natural Gas Pipeline Compression Costs

Posted in Industry News, Litigation, Oil & Gas Contracts, Pipeline, Texas

In Kachina Pipeline Company, Inc. v. Lillis, No. 13-0596, the Supreme Court of Texas interpreted a natural gas-purchase contract and held that a producer was not required to share in the costs of compression, even though that compression helped yield a higher re-sale price. Whether this decision narrowly reflects the language of one specific contract or represents a sea change is yet to be determined.

Factual Background

Kachina Pipeline Company, Inc. (“Kachina”) operates a natural gas gathering system, as well as a gas pipeline.  Kachina utilized its pipeline to transport gas it purchased to Davis Gas Processing’s Plant (“Davis Plant”) where it was re-sold.  Michael Lillis (“Lillis”) was one of the producers who sold natural gas to Kachina, dating back to 2001.

In 2003, Kachina installed the “Barker Central Compression Station” (“Compression Station”) on its pipeline, which allowed it to resell the gas in the pipeline at its high-pressure inlet, increasing its re-sale value to Davis.  In 2005, Kachina (the Buyer) and Lillis (the Seller) entered into a new Gas Purchase Agreement (“Agreement”).  Under the Agreement, Lillis would transfer his gas into Kachina’s gathering system to be transported through the pipeline to the Davis Plant.  In exchange, Kachina would pay Lillis a percentage of the re-sale price it obtained from Davis. The Agreement had an initial five (5) year term, and was scheduled to expire in May 2010.  After the expiration of the initial term, the Agreement continued on a month-to-month basis, and could be cancelled by either party after thirty (30) days notice.  The Agreement also included a provision allowing Kachina to “continue the purchase of gas under the terms of this Agreement” if Lillis attempted to cancel the Agreement and sell to a third-party, provided Kachina would match the price terms offered by the third-party.

Procedural History

In 2008, Lillis contracted to sell his gas directly to Davis, and constructed his own pipeline to the Davis Plant.  Lillis then brought suit against Kachina, alleging that compression costs had been improperly deducted in breach of the Agreement.  Kachina counterclaimed, arguing that Lillis breached the Agreement by failing to notify it of Davis’ third-party offer, as well as a declaratory judgment allowing it to both:  1) take compression deductions under the Agreement;  and 2) exercise a renewal of Agreement until May 2015.  Both parties filed motions for summary judgment.  The trial court denied Lillis’ motion and granted Kachina’s motions.

Lillis appealed the judgment to the Third Court of Appeals in Austin, which reversed both declarations, and held that the Agreement did not allow Kachina to deduct compression costs, and that the Agreement was not extended until May 2015.  In a 6-3 decision, the Supreme Court of Texas agreed with the Third Court of Appeals on both issues, with Justice Brown writing the majority opinion.  Chief Justice Hecht, joined by Justice Green and Justice Devine, dissented.

Does the Compression Contract Require Payment?

Kachina asserted that the Agreement allows for deductions for “any compression that aids in the final delivery to Davis of gas bought from Lillis.”  Id. at *7.  Conversely, Lillis asserted that the Agreement allows for deductions for compression that Kachina installed only after Lillis fails to deliver gas that can be transported through the pipeline.  Under Lillis’ interpretation, Kachina would be required to show:  “1) that Lillis was unable to deliver gas against Kachina’s working pressure, and (2) the compression equipment was installed after the Agreement’s execution.”  Id. at *7-8.  That interpretation would exclude deductions related to the Compression Station, which was installed in 2003, two years prior to the Agreement.  The specific provision on pressure read as follows:

Pressure:  Seller shall deliver the gas deliverable hereunder, at the above[-]described delivery point at a pressure sufficient to enter Buyer’s pipeline against the working pressure maintained therein from time to time.  Seller will regulate its[] pressures so as to not exceed the maximum allowed operating pressure (MAOP) as set from time to time by Buyer for deliveries into Buyer’s gas pipeline.  However, it is expressly understood and agreed that neither party hereto shall be obligated to compress any gas under the terms of this Agreement and if the well is no longer capable of delivering gas against the working pressures maintained at the delivery point and neither party elects to install a compressor, then Buyer shall, upon request from Seller, release such well and the gas produced therefrom from the terms and provisions of this Agreement.  If Buyer installs compression to effect delivery of Seller’s gas, Buyer will deduct from proceeds payable to Seller hereunder a value equal to Buyer’s actual costs to install, repair, maintain and operate compression, plus 20% of such costs to cover management, overhead and administration.

(emphasis by Court).  The Court noted that the Agreement put the burden of maintaining sufficient well pressure (to overcome the working pressure in the pipeline) on Lillis.  If Lillis’ wells failed to do so, then the Agreement provided Kachina with two options:  “[i]t may do nothing, in which case the well will be released from the Agreement.  Or it may elect to install compression so that the well can overcome the working pressure.”  Id. at *11.  If Kachina elected the latter, the Agreement provided it was entitled to deduct compression costs.

Based on this framework, the Court viewed the ability to deduct costs for compression as entirely contingent, arising “only if [Kachina] installs compression to effect delivery.”  Id. at *11-12.  As a result, Justice Brown held that it could not apply to pre-existing compression, as the provision utilized the word “installation.”  That word choice would not make any sense if the parties intended Kachina to charge Lillis for pre-existing compression.  The opinion also held that “only compression installed for the purpose of overcoming Kachina’s working pressure is installed to ‘effect delivery.’”  Id. at 12.  The Court reasoned that “if a well’s natural pressure is sufficient to overcome the working pressure at the delivery point, added compression can hardly be said to bring about delivery that would occur without it.”  Id. at *12-13.

Kachina argued that the Compression Station, though pre-existing, “effects delivery” by “lowering suction” which reduced upstream pressure and aided the flow of gas into the pipeline.  Chief Justice Hecht also echoed this point in his dissent.  The Court found this position unavailing, noting that, while this compression may aid in delivery, it does not “effect delivery.”  Id. at *15

Kachina also alleged, and the dissent agreed, that Lillis would have been unable to deliver the gas to the pipeline without the compression.  The Court disagreed, distinguishing between the “high-pressure” sales made possible by the Compression Station, and Davis’ ability to take low-pressure gas (albeit for a lower resale price).

The Court, however, did make sure to clarify that the location of the pressure was not determinative on the question of whether compression can “effect delivery,” as compression can reduce upstream pressure as well as downstream pressure.  This point stood in contrast to the Court of Appeals, and was urged by two pipeline industry amicus briefs.  In closing, the majority noted that while downstream compression of gas “was both common and critical to efficient transportation,” the industry custom of producers willingness to share in those costs could not overcome the unambiguous meaning of the Agreement.  Id. at *19.

In his dissent, Justice Hecht argued that the summary judgment evidence conclusively established that Kachina’s compression was necessary to effect the delivery of Lillis’ gas, noting that appellee’s counsel conceded that, without any compression in the Kachina pipeline, Lillis’ gas could not enter the delivery system.  Moreover, he rejected the majority opinion’s temporal distinction based on the word “installation,” asserting that it makes little sense for Lillis to stop paying for compression (as under the parties’ previous agreement) only to resume paying for it when it became necessary under the 2005 Agreement.  In closing, the dissent stated:  “Today’s lesson is that producers’ agreements to share in compression costs are common and critical and will be enforced unless a court can think of a way to avoid them, regardless of the evidence.”  Id. at *28.

Did the Compression Contract Extend the Contract?

The Court also addressed the extension of the Agreement.  Kachina asserted that its right to “continue the purchase of gas under the terms of this Agreement” afforded it the right to extend the Agreement by another five (5) years, because the five-year initial period was a “term.”  The Court rejected this argument, noting that the extension merely allowed Kachina to “continue to purchase gas,” and that the Agreement explicitly became month to month as of May 2010.  In his dissent, Justice Hecht joined this portion of the opinion.

New EPA Stormwater Permit Adds More Restrictions to Allowable Wash Water Discharges

Posted in Environmental

On June 16, 2015, the EPA published a notice of final permit issuance for the NPDES General Permit for Stormwater Discharges from Industrial Activities (commonly referred to as the Multi-Sector General Permit or “2015 MSGP”). Click here to see the Multi-Sector General Permit. Many permittees will understandably focus on any changes made to the specific requirements for their sector. However, permittees should also pay attention to a change in permit coverage that affect all sectors; specifically, the list of allowable non-stormwater discharges found in section 1.1.3.1 of the 2015 MSGP.

The MSGP is designed to only cover certain stormwater discharges; however, the permit includes a limited number of non-stormwater discharges that are also authorized. The previous version of the MSGP included the following on the list of allowable non-stormwater discharges.

  • pavement wash waters where no detergents are used and no spills or leaks of toxic or hazardous materials have occurred (unless all spilled material has been removed)
  • routine external building washdowns that do not use detergents

The 2015 MSGP narrows the scope of these authorized non-stormwater discharges (emphasis added):

  • pavement wash waters where no detergents or hazardous cleaning products are used (e.g., bleach, hydrofluoric acid, muriatic acid, sodium hydroxide, nonylphenols), and the wash waters do not come into contact with oil and grease deposits, sources of pollutants associated with industrial activities (see part 5.2.3), or any other toxic or hazardous materials, unless residues are first cleaned up using dry clean-up methods (e.g. applying absorbent materials and sweeping, using hydrophobic mops/rags) and you have implemented appropriate control measures to minimize discharges of mobilized solids and other pollutants (e.g., filtration, detention, settlement)
  • routine external building washdowns/power wash water that do not use detergents or hazardous cleaning products (e.g., those containing bleach, hydrofluoric acid, muriatic acid, sodium hydroxide, nonylphenols)

In explaining the rationale for adding these additional restrictions, the permit fact sheet simply notes that “cleaning agents other than detergents…could clearly have the potential to cause water quality issues if discharged.” The agency is also concerned with the mobilization of particulates and other pollutants during washing activities, and included examples of appropriate control measures to minimize this.

One commenter asked EPA to define “hazardous cleaning products.” EPA declined to do so, but pointed to the examples in the permit itself as well as the definitions of “hazardous materials/substances” and “uncontaminated discharge” in Appendix A of the 2015 MSGP. The term “Hazardous Materials or Hazardous Substances or Toxic Materials” is defined in part as “any liquid, solid, or contained gas that contain properties that are dangerous or potentially harmful to human health or the environment,”while the term “Uncontaminated Discharge” is defined as “a discharge that does not cause or contribute to an exceedance of applicable water quality standards.” Unfortunately, these definitions do not shed much light on what cleaning agents are now prohibited under the MSGP. EPA also warns that “packaging claims regarding environmental safety (of cleaning products) are not a sufficient determinant of product suitability.” Faced with this uncertainty, permittees will need to be very careful about what cleaning products to use, or risk a regulator determining that one of its discharges is not authorized under the MSGP.

Texas Supreme Court Says You Can’t Disclaim Your Heritage, But Maybe You Can Ignore It

Posted in Industry News, Litigation, Oil & Gas Contracts, Royalty, Texas

Like the final season of ABC’s hit series Lost, the Texas Supreme Court’s opinion in Chesapeake Exploration, L.L.C. v. Hyder, No. 14-0302, was highly anticipated, but left many of us scratching our heads.  The 5-4 decision, authored by Justice Hecht, is the latest in a series of cases from high courts across the country addressing the sharing of “post-production costs” between royalty owners and oil and gas lessees.

To appreciate the significance of Hyder, one needs a little background on a debate that has been raging in Texas oil and gas law since the Spice Girls had their first number one single and classics like Independence Day, Mission Impossible (the first one), and Eddie Murphy’s The Nutty Professor graced our silver screen.  In states like Texas that follow the “at the well” rule, an oil and gas royalty owner usually takes his royalty share of production “at the well.”  This means that the royalty owner’s share will be free of the costs necessary to actually bring oil or gas to the surface (“production costs”), but he will generally bear his proportionate share of any additional costs that the lessee incurs after the oil and gas has been produced (“post-production” costs).  Courts in “at the well” states like Texas and Louisiana have generally recognized that these post-production activities (such as compression, transportation, and processing) add value to the raw oil or gas to the mutual benefit of both the lessee and royalty owners such that it is fair for the royalty owner to bear his proportionate share.

Post-production costs can be quite significant, however, depending on the location of the well and the particular costs at issue, and the savvy oil and gas lessors will almost inevitably attempt to contract out of these general rules.  Modern royalty clauses frequently include a provision stating that the lessor’s royalty will be cost free or will not bear the costs of marketing.  The effect of these clauses in Texas, has always been questionable in light of the Texas Supreme Court’s opinion in Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. 1996).  In Heritage Resources, the Supreme Court held that such “no deductions” clauses must be read in conjunction with the royalty provisions of the lease.  So, when a no deductions clause states that there can be no deductions from “royalty,” Heritage Resources mandates that the court first determine where “royalty” is calculated.  If calculated at the well, then the no deductions clause becomes mere surplusage because royalty at the well is already free of post-production costs.  Increasingly, therefore, the extra savvy lessor will include a provision in their lease expressly stating that Heritage Resources will not apply or that the “no deductions” clause should not be regarded as surplusage despite the holding in Heritage Resources.

Enter Hyder.  While the court construed other portions of the lease in passing, the core of the dispute in Hyder centered on an overriding royalty clause that provided for a “cost free (except only its portion of production taxes) overriding royalty of five percent (5.0%) of gross production.”  A separate paragraph of the lease also stated that the parties to the lease “agree that the holding in the case of [Heritage Resources] shall have no application to the terms and provisions of this Lease.”  Full discussion of the majority opinion’s analysis of these two lines far surpasses the few paragraphs’ traffic of our stage here.  However, we note with particular interest the finding by the court on the effect of the so called Heritage disclaimer.  The court found that such provisions had no effect and could not override the text of the lease.  Therefore, the Heritage disclaimer had no effect and the court expressly stated that it had no influence on the court’s decision.  Despite reaching this conclusion, the court, nevertheless, determined that the general statement that the overriding royalty was to be “cost free” referred to all costs both before and after production, and, therefore, Chesapeake had impermissibly taken deductions for post-production costs when calculating the overriding royalty.

Ironically, while denying parties to a contract the ability to disclaim it, the court appeared not to apply the Heritage Resources court’s analysis.  Assuming that “cost free” referred to all costs, the next question under Heritage Resources should have been “cost free from where?”  Instead of taking this next step under the Heritage Resources analysis, the majority opinion simply stated that the overriding royalty clause when “reasonably interpreted” freed the royalty from post-production costs as well as production costs.  The court further stated that Heritage Resources “holds only that the effect of a lease is governed by a fair reading of its text.” So, while not disclaimed, it will be interesting to see how the Texas Supreme Court applies Heritage Resources in the future.

Louisiana Supreme Court Denies Plaintiff’s Writ Application in a Move That Will Impact Oil & Gas Legacy Cases

Posted in Industry News, Litigation, Oil & Gas Contracts, Property Law

By: Joe NormanKelly Becker, James Lapeze, and Kathryn Gonski

Recently the Louisiana Supreme Court handed down a ruling that has significant implications on the oil and gas industry in the state. The Court denied the Plaintiff-landowner’s writ application which sought review of a Louisiana First Circuit Court of Appeal opinion that affirmed dismissal of the landowner’s claims based upon application of the subsequent purchaser doctrine in favor of defendants who were mineral lessees.

Previous Court Ruling

In many cases alleging damage to property arising from historic oil and gas operations, the plaintiff was not the owner at the time of the alleged damage, but instead is the subsequent purchaser of the property at issue.  In Eagle Pipe and Supply, Inc. v. Amerada Hess Corp., 10-2267 (La. 10/25/11), 79 So. 3d 246, a case that involved a predial (not a mineral) lease, the Louisiana Supreme Court held that whether damage to property is apparent or unapparent, the right to sue for such damage is a personal right that belongs to the landowner at the time the damage occurred unless the right has been explicitly assigned or subrogated to the subsequent buyer of the land.  The rationale of the holding is that a claim for damage is a personal, not a real, right and that a subsequent purchaser’s remedy is limited to a suit to rescind the sale or recover damages against its seller.  After this decision, plaintiffs involved in legacy litigation have taken the consistent position that Eagle Pipe’s holding was inapplicable to damage caused by parties holding rights to explore for oil and gas under mineral leases or other instruments since the nature and source of those rights are different from rights flowing under a typical commercial or other predial lease.

Mineral Lease Ruling

In Global Mktg. Solutions, L.L.C. v. Blue Mill Farms, Inc., 2013-2132 (La. App. 1 Cir. 9/19/14), 153 So. 3d 1209, the First Circuit considered directly the applicability of the subsequent purchaser doctrine in a case involving mineral leases.  The First Circuit rejected plaintiff’s argument that the subsequent purchaser doctrine was inapplicable to mineral rights and applied the Supreme Court’s opinion in Eagle Pipe to bar the Plaintiff’s tort, contract, and Mineral Code claims for alleged contamination of property caused by oil and gas operations that occurred prior to the Plaintiff’s acquisition of the property.   On April 23, 2015, the Louisiana Supreme Court denied the Plaintiff’s writ application in a 4-2 vote.  In a separate concurrence, Justice Crichton unequivocally stated that the analysis of the subsequent purchaser rule articulated in Eagle Pipe is equally applicable in the Mineral Code context.

A copy of the First Circuit decision can be found here.   A copy of Justice Crichton’s concurrence to the Louisiana Supreme Court’s writ denial can be found here.

Supreme Court of Texas Clarifies How to Prove Lost Value

Posted in Exploration and Production, Litigation, Oil & Gas Contracts, Texas

By Andrew Wooley

On May 8, 2015, the Supreme Court of Texas held in Phillips v. Carlton Energy Group, LLC[1]/ that an expert witness’s pre-suit evaluations of a coal bed methane concession in Bulgaria and his and another expert’s opinion testimony at trial were too speculative to support a jury’s damage finding for tortious interference related to the concession, but that several bona fide offers to purchase an interest in the concession, even if based on the same pre-suit expert evaluations, were “reasonably certain” valuation evidence potentially sufficient to support a damage award.

The decision is noteworthy for two reasons.  First, it extended the existing requirement that lost profits be proved with “reasonable certainty” to proof of lost value when valuation is based on an extrapolation of estimated profits.  (“We can think of no reason … why it would make sense to deny damages based on speculative evidence of lost profits but allow recovery of lost value based on the same evidence.”)  Second, by its holding that bona fide offers in a recognized market to buy or sell an asset can be reasonably certain evidence of value, even if the offers are based on unverifiable assumptions and speculative extrapolations, the supreme court clarified in Phillips that the “reasonable certainty” required to prove lost value is not the same as that required to prove lost profits: “[W]hen evidence of potential profits is used to prove the market value of an income-producing asset, the law should not require greater certainty in projecting those profits than the market itself would.”

The trial court in Phillips entered judgment for the plaintiff on its tortious interference claim against defendant Phillips, subject to a remittitur of the jury’s $66.5 million damage finding to $31.16 million.  The plaintiff conditionally agreed to the remittitur, and both the plaintiff and Phillips appealed.  The court of appeals reversed the remittitur and other aspects of the trial court’s judgment, and rendered judgment for the plaintiff on the jury’s verdict.[2]/  Phillips and the other defendants successfully petitioned the supreme court for review.  The supreme court has jurisdiction over questions of law, which it exercised to clarify that proof of lost value requires “reasonable certainty” but that the meaning of “reasonable certainty” for proof of lost value is not exactly the same as “reasonable certainty” for proof of lost profits.  The supreme court does not have jurisdiction to decide whether a particular jury finding is supported by factually sufficient evidence, however, so it necessarily remanded that question to the court of appeals for its determination.  The court of appeals will therefore reconsider the evidence in the record of the fair market value of the plaintiff’s lost interest in the Bulgarian concession in light of the “reasonably certain” criteria explained by the supreme court in Phillips and decide whether the record evidence is sufficient to support the jury’s award of $66.5 million damages and whether the trial court erred in suggesting a remittitur to $31.16 million.  No matter how the court of appeals disposes of the case on remand, the case may well end up before the supreme court a second time.

[1]/     58 Tex. Sup. Ct. J. 803, 2015 WL 2148951, 2015 Tex. LEXIS 439 (Tex. May 8, 2015).

[2]/    Carlton Energy Grp., LLC v. Phillips, 369 S.W.3d 433, 465 (Tex. App.—Houston [1st Dist.] 2012).

EPA and BSEE Team Up to Resolve Offshore Environmental Violations

Posted in Environmental

Recently, when there was talk about Houston-based ATP Oil and Gas’ (ATP) legal problems, it was inevitably about its bankruptcy and its effort to bring the overriding royalty interests it had conveyed back into the bankrupt estate as debt instruments. That should change now that the Department of Justice (DOJ), acting jointly on behalf of EPA and BSEE, has announced its settlement with ATP Infrastructure Partners (ATP-IP) in the first joint judicial enforcement action resolving alleged violations of both the Clean Water Act (CWA) and Outer Continental Shelf Lands Act (OCSLA).

This settlement should garner its own share of interest, if for no other reason, because BSEE and EPA are taking the issues serious enough to require all submittals to be signed by a responsible corporate official in addition to imposing a $1 million fine.

It highlights three trends that industry should be aware of: the willingness of EPA and BSEE to work together to address violations of environmental regulations off-shore, requiring corrective measures that include enhanced reporting and third-party auditing, and multiple mandated certifications by a designated officials.

The Violation

In March 2012, BSEE conducted an inspection of ATP’s floating production platform facility, known as the ATP Innovator, while it was moored to the sea floor about 45 nautical miles offshore of southeastern Louisiana (about 125 miles south of New Orleans) and engaged in the production of oil and natural gas. ATP operated a float cell on the platform as an essential part of its wastewater treatment system to separate and remove oil and suspended solids from its produced water prior to its discharge into the Gulf. During the inspection, BSEE officials discovered a metal tube “hidden in the rafters” that went from a tank holding Cleartron ZB-103, a water clarifier that the government alleges was used as a dispersant, to the outfall pipe at a location downstream of the designated NPDES sampling point; thus, making the added chemical undetectable in required NPDES samples.

According to the complaint (PDF) DOJ filed in February 2013, Cleartron ZB-103 was routinely “injected into the outfall pipe to mask oil sheen on the ocean surface resulting from ATP’s discharge of wastewater containing quantities of oil in excess of its NPDES permit limit.” DOJ further alleged that this setup was intended to allow ATP to mask any oil sheens resulting from the discharge of wastewater that exceeded the permit limit for oil content. Under the NPDES General Permit, the Oil & Grease content of produced water discharges is limited to a monthly average of 29 mg/L and a daily maximum of 42 mg/L, and the General Permit only requires the collection of Oil & Grease samples once per month.

However, permittees are also required to sample their produced water discharge for Oil & Grease any time that a sheen is observed in the vicinity of the discharge. Thus, the mere presence of a produced water sheen is not necessarily a permit violation, but it will necessitate additional sampling to determine if a violation has occurred. The government also noted that the Cleartron ZB-103’s MSDS states that it is harmful to aquatic life. For these reasons, the government claims that the discharge of Cleartron ZB-103 in this manner was an unlawful discharge of a CWA “pollutant.”

Following the BSEE inspection, the piping that ran from the Cleartron ZB-103 tank to the discharge pipe was removed, the ATP Innovator ceased operations and was removed from the deepwater. It now resides at the Port of Corpus Christi, Texas, sitting idle with no plans for future use in United States waters.

The DOJ filed its complaint against two entities—ATP and ATP-IP. ATP is the ATP Innovator’s operator and ATP-IP is the platform’s owner. Sometime after the BSEE inspection, but before DOJ filed its complaint, ATP declared bankruptcy citing reduced cash flows caused by the deepwater drilling moratorium instituted after the 2010 Deepwater Horizon oil spill. Normally, the automatic stay afforded to bankrupt entities would protect these entities against litigation, but the DOJ’s enforcement action was exempt from the automatic stay based on a “police and regulatory” exemption. ATP’s bankruptcy has not been resolved; therefore, the government’s claims against it await resolution.

The government’s Complaint alleges six causes of action:

  1. CWA § 309(d) civil penalties for violations of CWA § 301(a) for unauthorized chemical dispersant discharges;
  2. CWA § 309(d) civil penalties for permit violations;
  3. CWA § 311(b)(7)(A) and (D) civil penalties for oil discharge violations;
  4. Injunctive relief under OCSLA, 43 U.S.C. § 1350(a);
  5. Injunctive relief under CWA Section 309(b); and
  6. Declaratory judgment declaring the applicability of the police and regulatory exception to the Bankruptcy Code’s automatic stay pursuant to 11 U.S.C. § 362(b)(4).

ATP-IP unsuccessfully sought to have all of DOJ claims against it (Claims 3, 4, and 5) dismissed. See United States v. ATP Oil & Gas Corp., 955 F.Supp.2d 616 (E.D. LA. 2013).

The Relief Sought by the Government

Both EPA regulations and the General NPDES permit restrict the discharge of dispersants into the ocean or any other waters. See 40 C.F.R. § 110.4 & NPDES General Permit, Part I, Section C.3 (expressly stating that the “operator shall minimize the discharge of dispersants, surfactants and detergents except as necessary to comply with the safety requirements of [OSHA, BSEE, and BOEM]… .). The DOJ alleged that ATP had been discharging significant quantities of dispersants, i.e., Cleartron ZB-103, on a daily basis, from October 2010 to March 2012—a period of about 16 months which at a statutory maximum of $37,500 per day for each of the three violations listed above exposed ATP to a maximum potential fine of about $54 million.

In addition to statutory penalties, the DOJ sought injunctive relief measures under both the CWA and OCSLA for operational practices to prevent future unauthorized discharges of pollutants into the offshore waters. This included the pipe setup itself, which still exist, in part, because only the pipe itself was removed, leaving the tube for use in future permit violations.

ATP-IP’s Consent Decree

To resolve this enforcement action, ATP-IP agreed to pay a $1 million fine and perform corrective measures including the permanent elimination of the Cleartron ZB-103 access point in the wastewater discharge outfall pipe. More importantly, the Consent Decree (PDF) requires that at least 30 days before anyone uses the ATP Innovator again for exploration, development, or production activities in US waters, ATP-IP will certify to the government that:

  • The platform has sufficient wastewater treatment equipment and operational plans to meet and maintain CWA permit discharge limits and prevent unlawful discharge of pollutants.
  • The platform’s surface production-safety systems will be maintained in a manner that provides for protection of the environment in accordance with BSEE’s regulations.
  • All platform operations will be performed in a safe and workmanlike manner in accordance with BSEE’s regulations.

As a further safeguard, with respect to the platform, ATP-IP must notify the DOJ, EPA and BSEE if any of the following actions occur:

  • The addition of any wastewater treatment equipment or surface production-safety equipment before the requisite certification is made.
  • Removal of the tube and permanent sealing of the discharge pipe.
  • Plans for its sell or transfer of ownership.
  • Plans for its salvage or scraps.
  • Plans for its use or lease for exploration, development, or production activities.
  • The required third-party audit of its wastewater treatment operations and surface production-safety systems for compliance with the CWA and OCSLA.
  • After every six months, its location and ownership.

Each Notification, Certification and Report Must be Signed By a Responsible Corporate Official

In a showing of how serious BSEE and EPA are taking these alleged violations, the consent decree requires each of the above notices, certifications and audit reports submitted by ATP-IP to the government to be signed by a responsible corporate official with the following certification:

I certify under penalty of law that this document and all attachments were prepared under my direction or supervision in accordance with a system designed to assure that qualified personnel properly gather and evaluate the information submitted. Based on any personal knowledge I may have and my inquiry of the person or persons who manage the system, or those persons directly responsible for gathering the information, the information submitted is, to the best of my knowledge and belief, true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fine and imprisonment for knowing violations.

The consent decree neither defines the term “responsible corporate official.” It is unclear whether this term will be interpreted as consistent with the similar provisions of the NPDES signatory rule. See 40 C.F.R. 122.22. The above certification language is almost identical to that which is required by NPDES regulations that must be signed by a responsible corporate officer or their duly authorized representative. See 40 C.F.R. § 122.22 (d). If the term “official” as used in the consent decree is equivalent to “officer,” then the only real difference is that the consent decree does not allow a “duly authorized representative” to sign the above-required certifications.

Conclusion

This consent decree is significant because it shows for the first time EPA, BSEE and DOJ working together, locally and in Washington D.C., to impose enhanced monitoring and auditing requirements on entities subject to enforcement actions for environmental violations in the Gulf of Mexico. The best means for avoiding liability in this case is to document compliance programs and due diligence in reviewing permit related submittals with those who prepared the documents to ensure their accuracy..

This is clearly an attempt by the government to change the corporate culture at ATP-IP and to send a message to the rest of the regulated community. While monetary penalties generally imposed upon a company may not sufficiently deter certain types of risk-taking within a corporation’s culture, making a corporate official personally assume responsibility and even potential criminal liability for the accuracy of government submittals related to compliance with a consent decree should get every executives attention and hopefully their attention will radiate across their company and perhaps the industry.

Ultimately, this case underscores the government’s expectation that upper management be actively involved in ensuring corporate compliance with federal environmental laws. Corporate executives and in-house counsel in heavily regulated environments are well-advised to implement effective compliance programs and to ensure that such programs are actually followed in order to avoid even the specter of personal liability.

Sierra Club Asks Court to Ban Use of Legacy DOT-111 Tank Cars

Posted in Environmental

As if crude producers and midstream transportation companies don’t already have enough problems trying to get crude oil from production fields to refineries thanks to inadequate pipeline infrastructure, tank car supply, rail safety concerns, and new regulations, they now also have to address a new, potentially market-busting lawsuit. In September, the Sierra Club, one of the largest environmental organizations in the United States, filed a lawsuit seeking an immediate ban on the transportation of crude oil in allegedly outdated and unsafe tank cars despite the fact that the government has proposed regulations to address the same concerns.

The Proposed Regulations

Following a series of train accidents in 2013, and a number of petitions asking for more stringent railroad safety regulations, the Pipeline and Hazardous Materials Safety Administration (PHMSA) and Federal Railroad Administration (FRA) published an advance notice of proposed rulemaking (ANPRM) on September 6, 2013. At the requests of the Sierra Club, the government extended the comment period to allow additional time for more public participation and both the Sierra Club and ForestEthics (the NGOs) submitted comments relevant to the proposed rulemaking.

The Petition for an Emergency Ban

Not willing to wait for the wheels of government to turn, the two NGOs jointly filed a petition with the Secretary of Transportation on July 15, 2014, just before the proposed rules were to be published, asking DOT to issue an emergency order banning the use of unjacketed (legacy) DOT-111 tank cars to ship Bakken crude and other highly flammable crude oil. The petition claims that unjacketed DOT-111 are unsafe because in rail accidents the cars are prone to puncture, spill oil, and trigger fires and explosions. They argue that the continued use of these tank cars poses an “imminent hazard.”

Instead of directly responding to the NGOs’ petition, the government issued a Notice of Proposed Rulemaking, as planned, about two weeks later. We reported in our recent blog entry about the content and impact of these new rules, which proposes three options for phasing out of the legacy DOT-111 tank cars, none of which includes an immediate ban on their continued use. Thus, if finalized as proposed, the new rules would shippers to continue to use legacy DOT-111 tank cars to ship Bakken crude until October 2018.

The Writ of Mandamus

Although the proposed rule addresses many of the DOT-111 safety concerns by requiring retrofits and operational changes, the NGOs claim that the proposed four-year phase-out of legacy tank cars is a “glacial pace [that] is unacceptable.” Thus, they filed an original Writ of Mandamus with the United States Court of Appeals for the Ninth Circuit on September 11, 2014, seeking to force the DOT to respond their petition for an immediate ban. For a legal basis, the NGOs argue that the All Writs Act gives the Ninth Circuit Courts of Appeals jurisdiction and they claim that the DOT has violated the Administrative Procedure Act a number of ways by taking an unreasonable amount of time to respond to their Rail Car Petition.

First, the NGOs claim that threat posed by the continued use of legacy DOT-111 tank cars is so severe that the 2018 ban contemplated in the proposed rules is simply too extended. Second, they even argue that the threat of harm is so great that the rulemaking process itself will take too long and leave too much to chance. For these reasons, they claim that the DOT had an obligation to respond to their petition for emergency order within a reasonable time, i.e., 30 days. Third, the NGOs argue shippers, who own the legacy DOT-111 tank cars, lack the necessary incentives created by financial liability to stop using DOT-111 tank cars to ship Bakken crude because they generally do not bear liability for rail accidents once a rail carrier accepts a shipment. And finally, the NGOs claim that the DOT’s proposed delay banning the DOT-111 tank cars will cause prejudice because Canada has already banned the DOT-111 tank cars; thereby incentivizing North American marketers to use the unsafe DOT-111 tank cars in America and the newer and safer tank cars in Canada until after the 2018 ban.

The NGOs acknowledge that most “unreasonable delay cases” entail lengthier delays involving rulemaking proceedings that take years to complete, but argue that their petition is unique and different because it seeks an “emergency action” to abate an imminent hazard that cannot wait for a rulemaking because “lives are at stake.” Likewise, while the NGOs admit that “there is no per se rule as to how long is too long, [they nonetheless claim that] ‘a reasonable time for agency action is typically counted in weeks or months, not years,’ particularly when urgent health or environmental harms are at stake, as the case here.” Citing In re American Rivers, 372 F.3d 413, 419 (D.C. Circuit 2004).

A Case to Follow

On September 22, 2014, the Ninth Circuit denied the petitioners’ request for an expedited decision but ordered the DOT to respond to the NGOs’ writ. The court specifically directed the DOT to propose a timeline for its response to the Rail Car Petition. According to the briefing schedule, the Ninth Circuit’s ruling will likely come in early 2015.

Crude oil producers should keep an eye on how the Court and the agency address the NGOs’ request because if the DOT ultimately bans legacy DOT-111, the marketplace would immediately lose about 25 percent of tank cars available to transport crude oil in North America, creating an immediate shortage of rail cars until the industry can manufacture new tank cars using the newer standards.

Liskow & Lewis Attorney to Participate in TexFed Oil & Gas Conference

Posted in Tax

In early November, the Texas Federal Tax Institute will host the TexFed: Oil & Gas Tax Conference in New York City. This is the first time a conference of this nature will be held in the Big Apple, and I am honored to participate as a member of a panel that will explore farmout transactions, joint operating agreements and the use of tax partnerships to optimize the after-tax economics of these transactions.

With the re-emergence of the domestic oil and gas exploration and production business, oil and gas farmout transactions have returned to prominence as a means by which a party with an oil and gas property can join together with a party who has an interest in deploying its capital to exploit that property. Our panel will define, analyze and discuss customary domestic farmout transactions and the resulting tax consequences thereof, including when to elect to be excluded from the partnership tax rules and alternatively when to use the partnership tax rules to avoid traps for the unwary and achieve tax efficiencies for the farmout transaction. In particular, we’ll analyze and discuss the innovative “cash and carry” transaction, which, when properly implemented, can result in tax efficiencies for both the farmor and the farmee in the transaction.

The conference targets attorneys, accountants and corporate finance personnel with an interest in understanding how these transactions are implemented to meet the objective of the parties. The conference will cover a broad range of issues including the tax rules for oil and gas operations, master limited partnerships, financing oil and gas activities through volumetric production payments, investments by tax-exempt investors and application of the at-risk and passive loss rules. In short, the conference is a comprehensive overview of current issues that industry tax, corporate finance, merger and acquisition, accounting and legal personnel need to understand. There also will be networking events which offer the attendees the opportunity to meet new people and make new connections in the industry.

I’m looking forward to seeing many of my friends and contacts in New York next month, and I hope you’ll consider joining us at the conference as well. Visit the Texas Federal Tax Institute’s website to register.

Trans Energy Settlement Shows Need for E&P Wetlands Compliance Strategy

Posted in Environmental

On September 2, 2014, the Department of Justice announced a settlement in United States v. Trans Energy, Inc., No. 14-117 (N.D.W.Va.), requiring the oil and gas company to pay $3 million in civil penalties and to spend approximately $13 million to restore 15 sites in West Virginia that had been developed without dredge and fill permits. The United States and the West Virginia Department of Environmental Protection alleged that the company impounded streams and discharged dirt, sand, rocks and other materials into streams and wetlands without permits to construct well pads, pipeline stream crossings, surface impoundments, and other structures relating to natural gas extraction. According to the Justice Department, the violations affected 13,000 linear feet of stream and more than an acre of wetlands.

The Trans Energy settlement shows that exploration and production (E&P) companies need a rigorous compliance strategy for wetlands permit requirements. In this regard, the legal commentary has placed a high degree of emphasis on the jurisdictional question under Section 404 of the Clean Water Act of whether a planned activity will involve the discharge of dredged or fill material into “waters of the United States.” See our previous blog entry on the proposed rule redefining the “waters of the United States” covered by the Clean Water Act.

On the other hand, the legal commentary has virtually ignored the importance of Nationwide Permits (NWPs) 12 and 39 to E&P activities. The Army Corps of Engineers (Corps) issues NWPs for activities that have minimal individual and cumulative adverse effects on the aquatic environment. The most recent versions of the NWPs were reissued in 2012, and they will be valid for five years, until March 18, 2017. See 77 Fed. Reg. 10184 (Feb. 21, 2012).

NWP-12 is for “utility line activities.” It authorizes activities required for the construction, maintenance, repair, and removal of “utility lines and associated facilities” in “waters of the United States,” provided the activity does not result in the loss of greater than 1/2-acre of “waters of the United States” for “each single and complete project.” 77 Fed. Reg. at 10271. “Utility lines” are defined broadly enough to include oil and gas gathering lines. In addition, NWP-12 expressly authorizes the construction of access roads for the construction and maintenance of “utility lines,” with certain limitations. NWP-12 requires pre-construction notification to the Corps only for seven specified types of circumstances, including where:

  • A Rivers and Harbors Act Section 10 permit is required;
  • The length of the “utility line” in “waters of the United States” exceeds 500 feet; or
  • The discharge results in a loss of more than 1/10th of an acre of “waters of the United States.”

Id. at 10272.

Moreover, NWP-39 authorizes discharges of dredged or fill material into non-tidal “waters of the United States” for the construction or expansion of commercial and institutional building foundations and building pads and attendant features necessary for the use and maintenance of the structures. The discharge must not cause the loss of greater than 1/2-acre of non-tidal “waters of the United States,” including the loss of no more than 300 linear feet of stream bed (unless for intermittent and ephemeral stream beds the Corps waives the 300 linear feet limit). Id. at 10279. Notably, the Corps has expressly stated that the construction of oil and gas well pads is a type of commercial development appropriate for authorization under NWP-39. Id. at 10223. Pre-construction notification is required for all NWP-39 permits.

The use of the NWPs also requires water quality certification under Section 401 of the Clean Water Act. The Louisiana Department of Environmental Quality has issued water quality certification (PDF) for NWP-12 without conditions, but it will issue such certification for NWP-39 only on a case-by-case basis. Likewise, the Texas Railroad Commission, which handles water quality certifications for federal permits covering activities associated with oil and gas exploration, development, and production operations, has issued water quality certification for activities under NWP-12 (PDF).

Individual Section 404 permits are not required when a nationwide permit is available. The E&P industry should utilize the NWP program as a way to streamline and simplify wetlands permit requirements. For more information about the NWP program, please contact Robert Holden or Lesley Pietras.

BSEE’s Investigations and Review Unit Changes the Playing Field on the OCS

Posted in Environmental

The Bureau of Safety and Environmental Enforcement’s (BSEE’s) Investigations and Review Unit (IRU) substantially enhances the civil and criminal enforcement of the Outer Continental Shelf Lands Act (OCSLA) and the regulations issued thereunder.

Background

In 2010, in the wake of the Deepwater Horizon oil spill, the Department of Interior renamed the Minerals Management Service (MMS) the Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE). DOI then restructured BOEMRE into three new Bureaus: BSEE, the Bureau of Ocean Energy Management (BOEM) and the Office of Natural Resources Revenue. The reorganization gave BSEE regulatory authority (PDF) over safety and environmental affairs for OCS exploration and production activities.

As part of the restructuring of the MMS, DOI Secretary Salazar established the IRU within BOEMRE via Secretarial Order No. 3304, issued June 29, 2010. The IRU was established (PDF) “to root out internal problems and target companies that aim to game the system.” Its purpose was “to establish the internal capability in BOEMRE” to: (1) promptly and credibly investigate and respond to allegations or evidence of misconduct and unethical behavior by BOEMRE employees and industry; (2) oversee and coordinate BOEMRE’s internal auditing, regulatory oversight and enforcement systems and programs; and (3) assure the ability of BOEMRE to swiftly assess and respond to emerging issues and crises on a Bureau-wide level, including spills and other significant events. Secretary Salazar originally intended the IRU’s functions to continue within the three new bureaus; however, as of fiscal year 2013, the IRU was operating only within BSEE (PDF).

Questions Regarding the Composition and Functioning of the IRU

The IRU describes itself as “a team of professionals with law enforcement backgrounds or technical expertise.” The head of the IRU reports to the BSEE Director. The current head of the IRU was formerly a supervisory special agent with the EPA’s Criminal Investigation Division. The IRU staff includes a federal criminal prosecutor and experienced law enforcement agents.

The Natural Resources Committee for the House of Representatives has questioned DOI about the IRU’s composition and activities. Rep. Richard Hastings (R-Wash.), House Natural Resources Committee Chairman, on behalf of the Committee, said in a letter (PDF) to Secretary Salazar, dated March 4, 2013, “More than two years after its creation, little is known about the IRU’s personnel, organization, and activities.” In particular, Rep. Hastings raised concerns about the IRU’s makeup, pointing to (1) BOEMRE’s 2010 request for $5.8 million (PDF) to equip the IRU and staff it with twenty new employees; (2) a 2012 statement by BOEMRE Director Bromwich “that the IRU would be staffed by prosecutors, investigators, and scientists;” (3) BSEE’s description of the IRU as “a team of professionals with law enforcement backgrounds or technical expertise;” and (4) a 2012 job listing for IRU special investigators noting duties including collecting evidence and witness statements. According to Rep. Hastings, it was “unclear how many people actually work in the IRU, what their backgrounds and expertise are,” whether they “serv[e] in a law enforcement capacity” or are authorized to carry firearms, and “how they are to interact with witnesses or collect evidence. . . .”

Rep. Hastings was particularly concerned that the IRU had been acting as a law enforcement organization beyond its authority and without sufficient oversight by the DOI, Congress or the public, instead reporting only to the BSEE Director. Rep. Hastings requested that the DOI produce any policies and guidance concerning coordination between the IRU and the DOI’s Office of Inspector General (DOI-OIG) or Ethics Office, as well as any status reports or results of investigations provided by the IRU to the DOI-OIG. The Natural Resources Committee has received a response from the DOI, but the DOI response is not publicly available at this time.

IRU Investigations

The IRU shares BSEE’s regulatory jurisdiction. It investigates violations of safety and environmental regulations in parallel with and in addition to ordinary BSEE investigations. Typical BSEE investigations are conducted by BSEE district personnel and are fact-finding proceedings. These investigations may result in the issuance of Incidents of Noncompliance (INCs) with requirements for corrective actions and/or the imposition of civil penalties. See 30 C.F.R. §§ 250.191, 250.1404. In all but the most egregious cases, the typical civil enforcement action has in the past been resolved with the correction of the noncompliance and the payment of any required civil penalty.

The IRU has an investigatory role greater than that of BSEE inspectors. The IRU investigation may be triggered by an accident, a whistleblower, or an INC. The IRU concentrates on matters involving serious personal injury or harm to the environment, or serious risks of such harm. If after a detailed investigation, the IRU determines that a criminal violation may have occurred (i.e., a willing and knowing violation of the statute, regulations, or lease provision, see 43 U.S.C.§ 1350(c)), the IRU may refer the investigation to the DOI-OIG for further investigation. With respect to an investigation that has been triggered by an INC, the IRU or DOI-OIG investigation may continue regardless of whether the INC has already been resolved or any civil penalty paid.

In contrast to the IRU, the DOI-OIG has criminal enforcement authority within the agency. (The DOI-OIG agent is the counterpart to an FBI agent in a regular criminal investigation.) The DOI-OIG may then refer the case to the United States Attorney’s Office for criminal prosecution, which in turn may bring the matter before a grand jury to seek an indictment.

The IRU investigation of an INC may not be apparent to an operator. An operator that has been issued an INC can no longer assume that the matter is closed simply because it corrected the noncompliance and paid a civil penalty—an investigation could be ongoing within the IRU. For example, an operator might only learn of the IRU investigation when it receives a request from the IRU to provide documents and/or make its employees available for interviews. Operators should know that if an investigation proceeds to IRU interviews of the operator’s employees and contractors, the IRU considers the violation to be a serious issue with possible criminal implications. Failure to cooperate in an IRU investigation could itself be construed as a violation of the OCSLA.

The IRU has the authority to interview and take oral statements from employees and contractors. The IRU may tape record the interviews (generally the operator will only receive copies of the tapes after indictment). For reasons of logistics, the interviews are unlikely to take place offshore. The individual who is subject to an IRU interview has a clear right to have his or her attorney present; however, the IRU will have discretion about allowing company attorneys to be present. The interview process itself raises a number of concerns, such as: (1) a government interview is intimidating and scary to employees; (2) the employees may be unaware of their right not to be interviewed; (3) the employees may be unaware of their right to their own counsel at the interview; (4) the employees may be unaware of the possible use of the interviews in a future criminal case; and (5) many employees may not be sophisticated about complex technical terms and actions on a rig or platform, creating a risk of miscommunication of regulatory significance. For these reasons, when the IRU is conducting interviews, it makes sense for the operator to implement a pro-active legal response.

Conclusions

We recommend that operators respond to and treat accident investigations and INCs more carefully than ever. Accidents involving serious injuries and INCs involving serious environmental and safety risks will receive heightened scrutiny by BSEE’s District Office and the IRU. It is not only actual harm, but also the risk of harm, either to an individual or to the environment, that triggers criminal enforcement. The IRU is now a mature organization, staffed with highly capable and experienced investigators tasked with ensuring more active enforcement of BSEE regulations. OCS operators and their counsel should be aware of the heightened risk of criminal investigations and possible prosecution.

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