The Energy Law Blog : Energy Lawyer & Attorney : Liskow & Lewis Law Firm : Gulf Coast, Offshore

By Robert E. Holden

The recent decision by the U.S. Court of Appeals for the Fifth Circuit in Center for Biological Diversity, Inc. v. BP America Production Co., et al, no. 12-30136 (5th Cir. Jan. 9, 2013) (“CBD”), reversed in part the district court’s dismissal of citizen suit claims against BP in connection with the Deepwater Horizon incident, upholding the citizen suit cause of action seeking to have BP submit EPCRA reports regarding the Macondo spill. CBD remains to be fully adjudicated, but CBD highlights the need for OCS operators to include EPCRA reporting in their release reporting plans.

Under EPCRA, any release that requires CERCLA reporting to the National Response Center requires EPCRA reporting, and any reportable quantity release of EPCRA-listed “extremely hazardous substances” also requires EPCRA reporting. The EPA EPCRA regulations specify that immediate emergency release notification must be provided to: 1) the “community emergency coordinator for the [Local Emergency Planning Committee (LEPC)] of any area likely to be affected by the release,” or if there is no LEPC, “the relevant local emergency response personnel;” and 2) the State Emergency Response Commission of any State “likely to be affected by the release.” 40 C.F.R. § 355.42(a). The EPCRA reporting regulations require both immediate reporting and follow-up written reporting “as soon as practicable.” 40 C.F.R. § 255.43. The CBD suit is focused on the written report provisions.

OCS operators may want to review their emergency release reporting programs to ensure EPCRA compliance.

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By Lesley Foxhall Pietras

On December 21, 2012, the Environmental Protection Agency (EPA) issued a policy announcement addressing how it will deal with source aggregation following the Sixth Circuit’s decision in Summit Petroleum Corp. v. EPA, 690 F.3d 733 (6th Cir. Aug. 7, 2012). (Our previous blog entry on this decision is available here.) In Summit, the Sixth Circuit concluded that the term “adjacent” implies only physical proximity, and EPA’s consideration of functional interrelatedness to combine geographically distant facilities into a single source for air permitting purposes was unlawful. EPA sought panel rehearing of that decision, but its request was denied. Summit Petroleum v. EPA, 2012 U.S. App. LEXIS 23988 (6th Cir. Oct. 29, 2012).

In the recent policy announcement, EPA stated that, due to Summit, the agency “may no longer consider interrelatedness in determining adjacency when making source determination decisions in its title V or NSR permitting decisions in areas under the jurisdiction of the 6th Circuit; i.e., Michigan, Ohio, Tennessee and Kentucky.” Memorandum from Stephen D. Page, Director, Office of Air Quality Planning and Standards, to Regional Air Division Directors, Regions 1-10, at 1 (Dec. 21, 2012), available here (PDF). EPA further declared, however, that it will continue to consider functional interrelatedness in areas outside of the Sixth Circuit. Id. (“Outside the 6th Circuit, at this time, the EPA does not intend to change its longstanding practice of considering interrelatedness in the EPA permitting actions in other jurisdictions.”).

Thus, although there was some hope that the Summit decision would restore adjacency to its plain meaning in all areas of the country, it appears that additional circuit courts will be required to weigh in before this administration adopts such a policy. In the meantime, industry likely will continue to point to Summit for persuasive authority for state or local permitting authorities.

EPA concluded the policy announcement by noting that it “is assessing what additional actions may be necessary to respond” to the Summit decision. Id. EPA therefore is likely still considering whether to file a petition for certiorari with the U.S. Supreme Court. 

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By Sarah Y. Dicharry and Robert E. Holden

After Deepwater Horizon, the President directed the Secretary of the Interior to develop a report concerning safety on the Outer Continental Shelf (“OCS”). In response, the Secretary of the Interior drafted a report entitled, “Increased Safety Measures for Energy Development on the Outer Continental Shelf,” which recommended a number of actions to increase safety. Following the report, the Secretary of the Interior directed BOEMRE to adopt and implement the report’s recommendations. Initially, BOEMRE implemented the recommendations through an interim final rule. In August 2012, BSEE promulgated a new final rule entitled “Oil and Gas and Sulphur Operations on the Outer Continental Shelf--Increased Safety Measures for Energy Development on the Outer Continental Shelf,” to tighten safety measures on the OCS. 77 Fed. Reg. 50856 (Aug. 22, 2012).

One example of the significant changes made by the new rule is the alteration to the decommissioning requirements, located in 30 CFR 250, subpart Q. As with the other areas of change, the changes to the decommissioning regulations seek to implement additional safety measures and promote consistency through the regulations. Specifically, the new final rule adds a section to 30 CFR 250, subpart Q regarding submission of decommissioning applications and reports when a blowout preventer (“BOP”) is used for abandonment operations, 250.1704(g)(1)(ii). 77 Fed. Reg. 50856, 50882 (Aug. 22, 2012). The new section extends the information requirements under section 250.1705 to decommissioning when the abandonment operations involve a BOP and allows operators to use the same BOP equipment in abandonment operations that they use in operations under other subparts of the regulations. 77 Fed. Reg. 50856, 50882, 50897 (Aug. 22, 2012). To promote consistency, it also imposes on operators the same regulatory oversight in decommissioning required in other subparts. 77 Fed. Reg. 50856, 50882 (Aug. 22, 2012). As such, operators must now provide additional information in their decommissioning applications when using a BOP during abandonment operations, including a description of their BOP system components as well as a schematic of the BOP system. 77 Fed. Reg. 50856, 50883 (Aug. 22, 2012). Operators must also incorporate third-party verification that: “blind-sheer rams installed in the BOP stack are capable of shearing any drill pipe under maximum anticipated surface pressure”; “the BOP stack is designed for the specific equipment on the rig and for the specific well design; the BOP stack has not been compromised or damaged from previous service; and the BOP stack will operate in the conditions in which it will be used.” Id. To satisfy the requirements of section 250.1705, operators must include evidence of the third-party’s qualifications, specifically showing that he is “a registered professional engineer, or technical classification society, or a licensed professional engineering firm capable of providing” the required verifications.

The rule makes multiple significant changes, including adoption of methods to assure sufficient redundancy of BOPs, promotion of well integrity, enhancement of well control, and integration of safety considerations at the management level. 77 Fed. Reg. 50856, 50857 (Aug. 22, 2012). The specific informational change regarding decommissioning discussed in this blog is only a glimpse into the new final rule. The implementation of this new final rule concludes the rulemaking efforts begun by the interim final rule in response to the recommendations of the Secretary of the Interior to improve safety on the OCS following the Deepwater Horizon incident.

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By Sarah Y. Dicharry and Robert E. Holden

In August 2012, the Bureau of Safety and Environmental Enforcement (“BSEE”) published a Notice to Lessees (“NTL”) seeking to clarify a number of ambiguities regarding BSEE’s interpretation and application of the Oil Pollution Act (“OPA”) regulations that require offshore lessees to prepare and submit regional Oil Spill Response Plans (“OSRPs”). United States Dep’t of the Interior Bureau of Safety and Environmental Enforcement, GUIDANCE TO OWNERS AND OPERATORS OF OFFSHORE FACILITIES SEAWARD OF THE COAST LINE CONCERNING REGIONAL OIL SPILL RESPONSE PLANS, NTL No. 2012-N06 (2012), available here (PDF) [hereinafter NTL 2012-N06]. With this NTL, BSEE seeks to clarify the OPA requirements for OSRPs and encourage lessees to include inventive and flexible response techniques in their OSRPs. Many of the clarifications are based on lessons learned from the Deepwater Horizon incident. To further BSEE’s goals, the NTL provides lessees with instructions for preparing their OSRPs, which are presented in an outline suggesting the organization and contents of OSRPs. While BSEE claims that compliance with the NTL’s instructions is not required for OSRP approval, BSEE strongly recommends compliance and indicates that its review of OSRPs will follow the guidelines established by the NTL.

Among other significant clarifications that BSEE makes in the NTL, the changes relating to the information that operators must include in the “Emergency Response Plan” section of their OSRPs are particularly important. For instance, the regulations require that the Emergency Response Plan identify a qualified individual who has “full authority to implement removal actions. . . .” 30 CFR 254.23. The NTL emphasizes that authority over “removal actions” must specifically include the authority to deploy “surface and subsea containment resources.” NTL 2012 N-06, 3. To demonstrate that a qualified individual listed in the OSRP can adequately respond to a Worst Case Discharge (“WCD”) scenario, the OSRP now must identify the response resources available, including personnel, materials, equipment, and support vessels. Also, 30 CFR 254.23(g) requires that, in the information submitted regarding the Emergency Response Plan, the operator identify procedures that will be used in the event of an actual or threatened spill, which must include “the methods to monitor and predict spill movement.” 30 CFR 254.23(g)(2). The NTL clarifies that “when identifying adequate provisions for monitoring the movement of a spill, you should use the distance of facilities farthest from shore.” NTL 2012 N-06, 5.

In the NTL, BSEE also makes some more minute clarifications in significant areas, including the calculation of WCD scenarios. For instance, 30 CFR 254.26 requires that the WCD discharge scenario be calculated according to the criteria in section 254.47. Section 254.47(a) requires that for “an oil production platform facility, the size of your worst case discharge scenario is the sum” of the factors listed in that section. The NTL provides, “[i]f the WCD scenario is an oil discharge from an oil production facility, calculate the initial volume of the WCD in accordance with the requirements of § 254.47(a).” NTL 2012-N06, at 28 (emphasis added). The NTL goes on to state, “[i]f operating from a production platform, also include the volume of all storage tanks and flowlines, and the volume of oil calculated to leak from a break in any pipelines connected to the facility.” Id. at 28-29 (emphasis added). Thus, for oil production facilities other than platforms, the NTL is consistent with the regulation; however for oil production platform facilities, the NTL seemingly includes additional requirements for calculating the WCD scenario oil volume. Also, Regarding its review of WCD scenarios in OSRPs, BSEE emphasizes that it will now evaluate not only the Effective Daily Recovery Capacity for particular equipment identified in the OSRP but also the availability of other technologies that could effectively respond to WCD scenarios. Further, while the regulations require that a WCD scenario response plan support a spill lasting up to thirty days, BSEE now strongly encourages that lessees identify supplies and materials that can sufficiently respond to a spill lasting longer than thirty days.

After a lessee submits an OSRP, BSEE’s Oil Spill Response Division analyzes the OSRP and determines whether or not it is sufficient to rectify the anticipated WCD scenarios identified therein. After BSEE approves an OSRP, the lessee is responsible for reviewing it every two years. If modifications are made after review, then lessees must submit the modifications to BSEE. Specifically, if a modification results in alteration of a regional OSRP, then the lessee must submit the revision within fifteen days of the change. If no modifications are made after review, then lessees must submit a writing to BSEE indicating that no changes were made. 

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By Sarah Y. Dicharry and Robert E. Holden

Following the Deepwater Horizon incident in May 2010, the DOI imposed a six-month moratorium on the issuance of new drilling permits in deep water and directed then-operating lessees to stop operations at the soonest time practicable. The DOI implemented the moratorium on issuance of new leases through a directive and Notice to Lessees (NTL), explaining that the DOI would not review applications for leases in deep water for the following six months. The DOI further implemented the moratorium on then-current leases by issuing letters to the lease operators.

In response to the moratorium, Hornbeck (an owner and operator of vessels that support deepwater operations) sued the DOI seeking declaratory and injunctive relief. Specifically, Hornbeck claimed that by issuing the directive and the NTL, the Secretary of the Interior violated the Administrative Procedure Act and exceeded his authority under the Outer Continental Shelf Lands Act. The district court granted the preliminary injunction, which prohibited the DOI from enforcing the Moratorium without providing greater explanation for its authority to do so. The DOI rescinded the initial moratorium and replaced it with second moratorium. The second moratorium was substantively identical to the first, but the DOI provided a more extensive explanation for the moratorium.

After the DOI issued its second moratorium, Hornbeck filed a motion to enforce the preliminary injunction. Specifically, Hornbeck argued that the DOI’s rescission and re-issuance of the moratorium disobeyed the court’s order enjoining enforcement of the initial moratorium. The court denied the motion. Shortly thereafter, the Secretary lifted the second moratorium, effectively mooting Hornbeck’s case.

Hornbeck then sought attorneys fees based on civil contempt and bad-faith litigation tactics. Hornbeck supported the civil contempt claim by demonstrating: (1) the DOI’s failure to seek a remand to the agency before taking additional administrative action; (2) the DOI’s continued public indications that it would reinstate the moratorium; and (3) the DOI’s continued communications to the industry that efforts to establish a new moratorium were underway. The district court found that, through those three actions, the DOI had failed to comply with the injunction. Thus, the district court concluded that Hornbeck established civil contempt by clear and convincing evidence and awarded attorneys fees of approximately $530,000. The district court did not reach the bad-faith litigation tactics issue.

The DOI appealed the district court’s decision to the United States Fifth Circuit Court of Appeals, which considered whether the DOI’s actions, taken without seeking a remand to the agency, violated the written order enjoining the enforcement of the initial moratorium. Hornbeck Offshore Servs., L.L.C. v. Salazar, __F.3d__, 2012 U.S. App. LEXIS 24355 (5th Cir. Nov. 27, 2012). The Fifth Circuit agreed with the district court that the DOI’s actions demonstrated its clear intent to overcome the injunction issued by the district court. However, the Fifth Circuit determined that for the DOI to have been in contempt of the order, the injunction would have had to require that the DOI seek a remand to the agency. Instead, the injunction only mandated that the DOI describe the manner and form of compliance with the injunction within 21 days; it contained no explicit obligation that the DOI seek to remand the decision to the agency before re-implementing a moratorium. Thus, the Fifth Circuit found that neither intending to overcome the injunction nor re-issuing the moratorium actually violated the district court’s order. On this basis, the Fifth Circuit overturned the district court’s award of attorneys fees based on civil contempt.

This Fifth Circuit decision significantly demonstrates that injunctions of regulatory action are limited to their express terms on review. Here it is arguable that the DOI effectively evaded the purpose of the district court’s injunction, and the Fifth Circuit upheld the agency’s actions. Clearly, unless injunctions anticipate and provide for the government’s potential opportunities to evade them, the injunctions may not achieve their purpose.

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By Robert E. Holden and Carlos J. Moreno

On October 1st, 2012, the Environmental Protection Agency (“EPA”) released the final NPDES general permit for discharges from oil and gas facilities in the western and central portion of the Outer Continental Shelf of the Gulf of Mexico (the “final permit”). The final permit has yet to be published in the Federal Register, but it is available here.

Operators already covered under the 2007 permit have until January 31, 2013 to file new Notices of Intent (“NOIs”) for continuous coverage. Permit coverage and compliance under the terms of the 2012 permit start when the new NOI is filed.

While many of the changes were already spelled out in the proposed permit, and summarized in our April 12, 2012 blog entry, operators should pay close attention to new provisions related to permit coverage. The final permit defines “Operator” as a party that falls in one of three categories: (1) Primary Operator (leaseholder or designated operator registered with BOEM), (2) Day-to-day Operator, and (3) vessel operator. The Primary Operator is the one that submits the NOI for coverage by block. However, other operators or vessel operators must file separate NOIs for discharges directly under their control but beyond the Primary Operator’s control (unless the Primary Operator already covered those discharges in its NOI).

This new language creates important changes in how discharges from Mobile Offshore Drilling Units (“MODUs”) are permitted in most of the Gulf of Mexico.

• Typically, the MODU operator will now have to obtain coverage for discharges that are solely controlled by it. These could include deck drainage, sanitary and domestic waste, and Cooling Water Intake Structure (“CWIS”) requirements.
• To address this issue, Oil and Gas Operators and Drilling Contractors may want to review their contractual provision on NPDES responsibility for all types of discharges.
• The MODU operator would have to obtain coverage in each lease block they plan to discharge in. The NOI for each new location must be submitted before the MODU commences drilling operations.
• The OCS operator’s existing discharges must be reauthorized by submission of a new NOI before January 31, 2013. This change may severely impact drilling in the event of expiration of coverage without timely NOI submission, undercutting permit continuation theories under the Administrative Procedures Act.
• NOI submittal must be done electronically and will require identification of the types of discharges under the control of the operator requesting coverage.

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By Lesley Foxhall Pietras

On October 5, 2012, EPA filed a petition for en banc rehearing of the D.C. Circuit’s August 21, 2012 panel decision vacating EPA’s Cross-State Air Pollution Rule (CSAPR). The panel, in a 2-1 decision authored by Judge Kavanaugh, held that CSAPR exceeded EPA’s statutory authority under the Clean Air Act (CAA) in two independent respects. First, the panel concluded that CSAPR may require upwind States to reduce their emissions by more than their own significant contributions to a downwind State’s nonattainment, contrary to the statute. Second, the panel concluded that EPA lacked authority to implement the required emissions reductions through Federal Implementation Plans (FIPs), rather than affording the States an initial opportunity to implement the reductions through State Implementation Plans. Read our previous blog entry on this decision here.

In its petition, EPA argues that the panel’s FIP holding conflicts with other D.C. Circuit decisions by reaching out to “invalidate EPA actions that were not before the Court and for which the statutory review period had previously run” and by “exceeding the Court’s proper role in statutory interpretation by rewriting the plain language of the Act.” Petition for Rehearing En Banc at 3 (pdf). Additionally, EPA contends the panel’s “‘significant contribution’ analysis misapplies the Act’s waiver and exhaustion requirements and ignores settled Circuit precedent in finding an unwritten proportionality requirement in the statute.” Id. at 9.

Rehearing en banc “is not favored and ordinarily will not be ordered” unless necessary to “maintain uniformity of the court’s decisions” or the proceeding involves a question of “exceptional importance.” Fed. R. App. P. 35(a). No response may be filed to a petition for an en banc reconsideration unless ordered by the court. Fed. R. App. P. 35(e). 

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By Jana Grauberger

The Texas Supreme Court distinguished several Texas appellate court decisions and held the exculpatory clause in a joint operating agreement (“JOA”) applicable not just to operational activities undertaken by the operator, but to all activities of the operator under the JOA. Reeder v. Wood County Energy, LLC, No. 10-0887, slip op. (Tex. Aug. 31, 2012). JOA exculpatory clauses often relieve the operator of liability to nonoperators absent a showing of gross negligence or willful misconduct on the part of the operator. In recent years, appellate decisions in Castle Tex. Prod. Ltd. P’ship v. Long Trusts, 134 S.W.3d 267 (Tex. App. – Tyler 2003, pet. denied), IP Petroleum Co., Inc. v. Wevanco Energy, L.L.C., 116 S.W.3d 888 (Tex. App. – Houston [1st Dist.] 2003, no pet.), Cone v. Fagadau Energy Corp., 68 S.W.3d 147 (Tex. App. – Eastland 2001, pet. denied), and Abraxas Petroleum Corp. v. Hornburg, 20 S.W.3d 741 (Tex. App. – El Paso 2000, no pet.), held that the exculpatory clause extends only to claims related to operations, i.e., drilling and not to other breaches of the JOA. The Texas Supreme Court stated that those cases all involved interpreting the exculpatory clause language of either the 1977 or 1982 A.A.P.L. Model Form Operating Agreements, which both require the operator to conduct “all such operations” in a good a workmanlike manner and only allow for liability as to nonoperators for failure to do such upon a showing of gross negligence or willful misconduct. In contrast, the JOA in Reeder was based on the 1989 A.A.P.L. Model Form Operating Agreement, which references “its activities under the agreement” in place of “all such operations.” The court agreed with commentators that the 1989 Model Form language provides more expansive protection for the operator than do the 1977 and 1982 Model Forms and requires a showing of gross negligence or willful misconduct in order to hold the operator liable to nonoperators in relation to any of the operator’s activities under the JOA. The court found insufficient evidence of gross negligence or willful misconduct as to claims against the operator in Reeder.

For a copy of the decision click here.

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By Stephen W. Wiegand

On August 21, 2012, the United States Court of Appeals for the District of Columbia Circuit vacated EPA’s Cross-State Air Pollution Rule (CSAPR). EPA issued CSAPR in August 2011 pursuant to Sec. 110(a)(2)(D)(i)(I) of the Clean Air Act (the “good neighbor” provision) which requires that State Implementation Plans contain adequate provisions to prevent a state’s emissions from affecting another state’s air quality. The CSAPR rule was promulgated in response to the D.C. Circuit’s remand in 2008 of EPA’s Clean Air Interstate Rule (CAIR), which was EPA’s prior attempt at implementing the good neighbor provision.

Under the rule, certain “upwind” states were required to reduce emissions of sulfur dioxide (SO₂) and nitrogen oxides (NO_x), based on those states’ contributions to downwind states’ air quality problems. Industry strongly criticized CSAPR for its draconian reductions in allowable power plant emissions. CSAPR would have required many states, including Louisiana and Texas, to reduce power plant emissions of SO₂ and NO_x, particularly during the summer ozone season. Industry challenged EPA’s data and methodology in formulating the CSAPR.

In a 2-1 decision, the Court vacated CSAPR on two main grounds. First, CSAPR required that upwind states reduce emissions by more than their own significant contributions to the downwind states’ nonattainment. Specifically, only states that contributed a threshold amount to the air pollution in a downwind state were subject to the provision. The restrictions placed on those states, however, were based on region-wide air quality monitoring projections. Thus, the rule could require states to reduce emissions by more than the amount of their actual contribution. Second, after quantifying the states’ obligations under the rule, EPA set forth those obligations in Federal Implementation Plans rather than giving the states the initial opportunity to implement the required reductions.

In vacating CSAPR, the Court ordered EPA to continue to administer CAIR pending the promulgation of a valid replacement.

The full opinion can be viewed here (pdf).

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