The Energy Law Blog

EPA Grants Reconsideration of Certain Oil and Gas Storage Tank NSPS Provisions Issued in August 2012

Katherine McCoy — Mon, 22 Apr 2013 09:03:10 -0500

On August 16, 2012, EPA issued new source performance standards (NSPSs) for the oil and gas sector. The standards applied to various sources including storage tanks used in crude oil and natural gas production. On April 12, 2013, EPA announced proposed amendments to the rule pertaining to storage tanks.

The proposed rule clarifies that the new NSPS standard applies only to vessels containing crude oil, condensate, intermediate hydrocarbon liquids, or produced water (i.e., vessels likely to emit volatile organic compounds (VOCs)).

Additionally, EPA explains in the proposed rule that it had initially underestimated the number of tanks that would be impacted by the final rule. Further, based on the agency’s revised estimation, there is currently an insufficient supply of control devices available to meet the October 15, 2013, deadline for compliance. Thus, EPA adjusted the compliance schedule as follows:

For tanks constructed after April 12, 2013, the proposed rule extends the deadline for compliance to April 15, 2014, or within sixty days after startup, whichever is later.
For tanks constructed prior to April 12, 2013, tank owners have until October 15, 2013 to report that the tank is on line and to provide the tank’s geographic coordinates. Further, if there is a change that would potentially increase the tank’s emissions, the owner or operator must install the required controls within sixty days of the change or by April 15, 2014, whichever is earlier.

The proposed rule also includes streamlined monitoring requirements for tanks that have already installed VOC controls and certain alternative emissions limits. Finally, the rule extends the deadline for submitting annual reports from thirty days to ninety days after the end of the compliance period.

Comments on the proposed rule must be submitted by May 13, 2013. EPA anticipates that it will take final action on the proposed rule by July 31, 2013.

For more information, click here.

OCS Operators Need to Consider EPCRA Reporting in their Release Reporting Plans

Katherine McCoy — Thu, 07 Mar 2013 12:13:40 -0500

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.

Air Permitting Update: EPA Ignores Summit Outside Sixth Circuit

Katherine McCoy — Thu, 10 Jan 2013 14:59:21 -0500

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.

DOI Promulgates a New Final Rule for Increased Safety Measures on the OCS

Katherine McCoy — Wed, 02 Jan 2013 10:45:40 -0500

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.

Implications of NTL 2012-N06 on OSRP Preparation and Review

Katherine McCoy — Fri, 28 Dec 2012 14:07:11 -0500

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.

Fifth Circuit Reverses District Court's Imposition of Attorneys Fees on DOI for Reissuance of Drilling Moratorium in GOM Following Deepwater Horizon Incident

Katherine McCoy — Fri, 28 Dec 2012 13:25:42 -0500

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.

EPA Finalizes NPDES Permit for Oil and Gas Facilities in the GOM OCS

Kelly Becker — Tue, 09 Oct 2012 08:57:22 -0500

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.

EPA Seeks Rehearing En Banc of D.C. Circuit Panel Decision on Cross-State Air Pollution Rule

Katherine McCoy — Mon, 08 Oct 2012 16:23:47 -0500

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).

Texas Supreme Court Holds JOA Exculpatory Clause Applicable to All Activities of Operator

Robert Theriot — Tue, 04 Sep 2012 14:57:05 -0500

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.

D.C. Circuit Vacates EPA's Cross-State Air Pollution Rule

Katherine McCoy — Fri, 24 Aug 2012 15:39:30 -0500

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).

Fifth Circuit Vacates EPA's Disapproval of the Texas Flexible Permits Program

Katherine McCoy — Tue, 21 Aug 2012 08:52:34 -0500

By Carlos J. Moreno

On August 13, 2012, the United States Court of Appeals for the Fifth Circuit vacated the Environmental Protection Agency’s (“EPA”) disapproval of revisions to the Texas State Implementation Plan (“SIP”) dealing with the state’s Flexible Permits program. State of Texas v. U.S. Environmental Protection Agency, No. 10-60614 (5^th Cir. Aug. 13, 2012). Under the Clean Air Act (“CAA”), EPA sets National Ambient Air Quality Standards (“NAAQS”) but states determine the specific control strategies that the individual state will use to achieve NAAQS. 42 U.S.C. § 7410(a)(1). The states do this by formulating and administering a SIP. 42 U.S.C. § 7410(a)(2). EPA has the authority to approve or disapprove SIP language proposed by the states. 42 U.S.C. § 7410(k). Petitioners challenged the EPA’s disapproval of the Texas SIP revisions relating to the Flexible Permits program under the CAA and the Administrative Procedure Act (“APA”).

In 1994, Texas revised its SIP to include a Flexible Permits Program and submitted the revisions to EPA for approval. The Flexible Permit Program allowed facilities that were minor sources for criteria pollutants to obtain a minor NSR permit setting an emissions cap for the whole facility. To determine the amount of the emissions cap, the state agency (Texas Natural Resource Conservation Commission, which later became the Texas Commission on Environmental Quality (“TCEQ”)) would first determine the corresponding emissions from each emissions unit under the cap if it had pollution controls at the BACT level. The cap amount was then set at the sum of the BACT emission values for the emission units within the facility. Facilities with flexible permits could make some modifications without the need for further agency review, as long as the resulting emissions total was still less than the emissions cap.

The EPA failed to take any formal action on the Flexible Permit Program for over a decade. In 2008, industry petitioners filed suit to force EPA to perform its nondiscretionary duty to act on the SIP revisions. The following year, EPA proposed disapproving the Program (final disapproval was issued on July 15, 2010). In the meantime, a number of facilities in Texas had obtained permit coverage under the Flexible Permit Program. In disapproving the SIP revisions, EPA argued that: (1) the Flexible Permit Program could allow major sources to evade NSR requirements applicable to major sources (Major NSR), (2) the monitoring, reporting and recordkeeping (“MRR”) provisions were inadequate, and (3) the methodology for calculating the emissions caps was not replicable.

The court examined EPA’s decision to disapprove the Flexible Permit Program under the usual APA standards for judicial review of agency action. In a 2-1 decision, the court found that in order for EPA to disapprove a SIP revision, it must demonstrate that the revision would “interfere with any applicable requirement concerning attainment of NAAQS or any other applicable requirement of the CAA.” See State of Texas v. U.S. Environmental Protection Agency, No. 10-60614, slip op. at 8 (5th Cir. Aug. 13, 2012) (quoting in part from 42 U.S.C. § 7410(l)). The court concluded that provisions in the Flexible Permit regulations requiring compliance with Prevention of Significant Deterioration (“PSD”) and Nonattainment review were sufficient to prevent major sources from using flexible permits to evade Major NSR, and that EPA’s insistence on an express negative statement to that effect had no basis in the CAA or applicable regulations. As to the MRR provisions, the court concluded that EPA’s concerns were solely based on misgivings about the level of discretion given to the state agency’s director when setting specific MRR permit requirements, and also had no basis in the CAA or applicable regulations. Finally, the court concluded that the CAA provisions and regulations for minor NSR do not require that the methodology for calculating emissions be identical from permit to permit.

The court vacated EPA’s disapproval of the SIP revisions and remanded it back to the agency for further consideration. Texas will probably submit new revisions to the SIP in an effort to address EPA’s concerns. In fact, TCEQ has already issued rules clarifying the scope of the Flex Permit Program, and has pledged to do rulemaking to address any MRR issues. However, many flex permit facilities have already switched to “non-flex” permits or are in the process of doing so. Regardless, this court opinion may prove to be a milestone for how future courts will review EPA’s decisions about SIP approval.

New Air Standards for Oil & Gas Industry May Force HAP Area Sources into Major Source Status

Katherine McCoy — Mon, 20 Aug 2012 09:03:40 -0500

By Robert E. Holden and Carlos J. Moreno

On August 16, 2012, EPA published a new rule that revises the NESHAP Subpart HH standards for the oil and gas industry. 77 Fed. Reg. 159 (Aug. 16, 2012). The Final Rule wassigned on April 17, 2012, but publication in the Federal Register did not occur until August 16, 2012, making the rule effective on October 15, 2012. The new rule contains many changes and new requirements for the industry. One important change is how the new definition of “associated equipment” modifies the aggregation rule for Hazardous Air Pollutants (HAP), which in turn modifies the applicability of the “major source” definition for oilfield operations, in particular as it applies to oil and gas wells, tanks and glycol dehydrators. Under the new rules, storage tank emissions will not be aggregated with well emissions, and storage tank and glycol dehydrator emissions may be aggregated separately.

Background

Section 112(n)(4) of the Clean Air Act, 42 U.S.C. § 112(n)(4), establishes a non-aggregation standard for exploration and production facilities, specifying that HAP emissions from oil and gas wells and compressor stations should not be aggregated for major source determinations. (Note that this rule does not apply to major source determinations for new source review or Title V.)42 U.S.C. § 7412 (n)(4)(A).Section 112(n)(4) provides:

[E]missions from any oil or gas exploration or production well (with its associated equipment) and emissions from any pipeline compressor or pump station shall not be aggregated with emissions from other similar units, whether or not such units are in a contiguous area or under common control, to determine whether such units or stations are major sources, and in the case of any oil or gas exploration or production well (with its associated equipment), such emissions shall not be aggregated for any purpose under this section.

42 U.S.C. § 7412(n)(4) (emphasis added); see also 40 C.F.R. § 63.761 (definition of “major source”).

The 1999 EPA NESHAP standard for oil and natural gas production facilities (Subpart HH) specified the equipment to be considered to be “associated” with oil and gas wells for purposes of the regulation. 64 Fed. Reg. 116 (Jun. 17, 1999). The 1999 standard defined the term “associated equipment” as:

Associated equipment, as used in this subpart and as referred to in section 112(n)(4) of the Act, means equipment associated with an oil or natural gas exploration or production well, and includes all equipment from the wellbore to the point of custody transfer, except glycol dehydration units and storage vessels with the potential for flash emissions.

Id. (emphasis added). For purposes of the rule, the point of custody transfer is defined as the point where hydrocarbon liquids or natural gas enter a pipeline or any other form of transportation, or the point where hydrocarbon liquids or natural gas enter a natural gas processing plant. Id.

Focusing on wells and storage tanks, the 1999 rule allowed the aggregation with well emissions of HAP emissions from tanks that do not have the potential for flash emissions (e.g., pressurized tanks).

New Oil & Gas Rule

The new rule modifies the definition of “associated equipment” by removing the “potential for flash emissions” qualifier after “storage vessels.” The definition now reads as follows: “Associated equipment, as used in this subpart and as referred to in section 112(n)(4) of the Act, means equipment associated with an oil or natural gas exploration or production well, and includes all equipment from the wellbore to the point of custody transfer, except glycol dehydration units and storage vessels.” Now the emissions of a larger universe of storage tanks, including those with no potential for flash emissions, may potentially be considered part of (and thus aggregated with) compressor station and pump station emissions, including those from glycol dehydrators.

EPA acknowledges that some “existing” production field facilities (constructed before August 23, 2011, the date of proposal of the new rules) that were previously “area sources” (i.e., non-major sources under Section 112), but that may now be major sources once the HAP emissions from storage tanks without the potential for flash emissions, are included. Thus, the new rule gives these facilities three (3) years from the effective date of the rule to comply with the relevant emission standards. Therefore, these facilities must be in compliance no later than October 15, 2015.

In light of the new rules, oil and gas operators should perform compliance reviews of their operations. As part of those reviews, industry should be alert to the effects of the modification of the aggregations rules for storage tanks. It remains to be seen what effect the recent decision from the Sixth Circuit on aggregation of Oil & Gas sources in the Title V context could have on future major source determinations under the revised NESHAP Subpart HH. See Lesley Foxhall Pietras, Air Permitting: Sixth Circuit Vacates Single Stationary Source Aggregation Determination for E&P Facilities Due to EPA’s Unreasonable Interpretation of Adjacent, The Energy Law Blog, Aug. 16, 2012.

Air Permitting: Sixth Circuit Vacates Single Stationary Source Aggregation Determination for E&P Facilities Due to EPA's Unreasonable Interpretation of Adjacent

Kelly Becker — Thu, 16 Aug 2012 09:15:18 -0500

By Lesley Foxhall Pietras

On August 7, 2012, in a 2-1 decision in Summit Petroleum Corp. v. U.S. Environmental Protection Agency, the United States Court of Appeals for the Sixth Circuit vacated the Environmental Protection Agency’s (EPA) determination that a natural gas sweetening plant and sour gas production wells commonly owned by Summit Petroleum Corporation (Summit) but dispersed over forty-three square miles constituted a single stationary source under the Clean Air Act Title V permitting program. Specifically at issue was EPA’s finding that the plant and the wells were “adjacent” based on their operationally interdependent relationship.

When making single stationary source determinations without the protection of the non-aggregation provision in Section 112 of the Clean Air Act, 42 U.S.C. § 7412(n)(4)(A), multiple pollutant-emitting activities can be aggregated together and considered a single stationary source only if, among other things, they “are located on one or more contiguous or adjacent properties.” See, e.g., 40 C.F.R. §§ 51.166(b)(6); 71.2. The question of what is “contiguous or adjacent” has long been vexing for the exploration and production industry. Under different administrations, EPA has changed its guidance on the meaning of this phrase. In 2007, in guidance specifically addressing oil and gas activities, EPA stated that “proximity is the most informative factor in making source determinations.” See Memorandum from William L. Wehrum, Acting Assistant Administrator, EPA, to Regional Administrators I-X, at 3 (Jan. 12, 2007). Two years later, EPA withdrew that guidance, reemphasizing the criteria set out in the regulations. See Memorandum from Gina McCarthy, Assistant Administrator, EPA, to Regional Administrators I-X (Sept. 22, 2009).

In Summit, the court concluded that the regulatory term “adjacent” is unambiguous and implies only physical proximity, citing the dictionary definition of “adjacent,” the term’s etymological history, and caselaw. In light of this determination, the court applied no deference to EPA’s interpretation of the term. See Summit Petroleum Corp. v. U.S. Environmental Protection Agency, No. 09-4348, slip op. at 15 (6th Cir. Aug. 7, 2012). EPA had argued that because “it has an established history of supplementing the traditional definition of adjacency with the concept of activities’ functional relatedness,” the court must review its interpretation with heightened deference. Id. at 16. The court rejected this argument, noting that “adjacent” is unambiguous and that “an agency may not insulate itself from correction merely because it has not been corrected soon enough, for a longstanding error is still an error.” Id. at 18.

Based on the plain meaning of “adjacent,” the court also rejected EPA’s interpretation “that activities can be adjacent so long as they are functionally related, irrespective of the distance that separates them.” See id. at 15. The court thus vacated EPA’s stationary source determination, directing EPA to reassess the aggregation of Summit’s facilities “under the ordinary understanding of its requirement that Summit’s plant and wells be located on adjacent, i.e., physically proximate, properties.” See id. at 16 (emphasis added).

While EPA performed the single stationary source determination in Summit because Summit’s plant and gas production wells are located on Indian territory, most other stationary source determinations are made by state and local regulators. Nonetheless, Summit should provide more clarity for all relevant permitting authorities, as it teaches that physical proximity must be considered in determining whether activities are “contiguous or adjacent.”

Louisiana Legislature Modifies Oilfield Cleanup Legislation

Katherine McCoy — Mon, 04 Jun 2012 10:16:54 -0500

By Rob McNeal

Updated June 15, 2012

Significant revisions and amendments to Louisiana’s oilfield cleanup legislation, La. R. S. 30:29 (commonly known as Act 312) obtained final legislative approval on May 31, 2012 and are expected to become law shortly. Procedures have been added to expedite the remediation of oilfield contamination, the procedures for the formulation of remediation plans by the Office of Conservation in the Louisiana Department of Natural Resources have been modified, and new provisions have been added to deal with various issues, including the admission of remediation evidence at trial. Generally, the legislation furthers the public interest in prompt remediation in accordance with Louisiana’s regulatory standards by encouraging the prompt assessment and remediation of contamination, rather than delaying cleanup activity until after trial in legacy lawsuits. These changes are summarized below.

ACT 312 BEFORE THE NEW LEGISLATION

Act 312 of the 2006 legislative session was enacted in response to judicial decisions that awarded significant damages for remediation costs with no obligation for landowners to actually use such awards for cleanup work. Defendants in such cases could avoid additional cleanup responsibility by operation of law as well as doctrines of res judicata and issue preclusion. The result was that contaminated property at issue in litigation was left unremediated despite conditions that exceeded regulatory standards. The courts recognized the negative public policy considerations created by this jurisprudence, but the Louisiana Supreme Court concluded that the solution was a legislative issue. The legislature responded by enacting Act 312.

Act 312 applies to private lawsuits which seek relief for oilfield contamination. In general, when a defendant is found liable for environmental damage, Act 312 provides that the court shall seek a recommendation from the Louisiana Department of Natural Resources, office of conservation (“LDNR”) with the parties’ input for the most feasible plan to remediate the contamination to regulatory standards and shall thereafter adopt the most feasible plan. The responsible party is required to deposit sufficient funds to implement the plan and thereafter the court and Louisiana Department of Natural Resources shall oversee the remediation. If necessary, the court can require the responsible party to provide additional funding or, conversely, the responsible party is reimbursed any excess funds not used for remediation.

However, a landowner can pursue a remedy or award for private claims suffered as a result of environmental damage with some limitations. Also, a landowner can receive damages for the implementation of additional remediation in excess of the requirements of the plan adopted by the court as may be required in accordance with the terms of an express contractual provision.

NEW LEGISLATION

Litigation over the application and interpretation of Act 312 had effectively delayed remediation of oilfield sites until after trial and impeded the prompt resolution of contamination claims. In addition, regulators were criticized for their handling of Act 312 issues. Due to both plaintiffs’ and defendants’ dissatisfaction with the existing law, two bills were passed that modify Act 312: House Bill 618 and Senate Bill 555.

House Bill Number 618 modifies Act 312 by amending the Louisiana Code of Civil Procedure. It enacts two new articles, 1552 and 1563. These articles provide for environmental management orders to expedite testing and a limited admission of environmental liability to allow defendants to remediate sites using the existing Act 312 procedure before trial on the merits.

Senate Bill Number 555 contains a variety of amendments to La. R.S. 30:29. It limits the timing of discovery of LDNR plan formulation evidence, creates a preliminary hearing to test the existence of environmental damage and liability for such damage, extends prescription for plaintiffs who perform environmental testing after giving notice, prohibits ex parte communications with LDNR and agency personnel prior to the issuance of a remediation plan, provides for additional agency review of LDNR’s plan, and adds a waiver of indemnity rights for punitive damage claims by any defendant who makes a limited admission of liability for environmental damage.

Suspension of Prescription

The new legislation protects plaintiffs from prescription while they investigate environmental contamination. A plaintiff can suspend the prescriptive period for any claim subject to Act 312 for one year by mailing or physical delivery of a notice of intent to investigate to LDNR. The notice of intent must include all of the following information:

A description of the property alleged to have been damaged;
A description of the alleged environmental damage;
The general location of the alleged environmental damage on the property;
The name and address of all known owners of the property; and
The name and address of the current operator.

In addition, the party issuing the notice of intent must mail a copy of the notice by certified mail return receipt requested to all persons identified in the notice.

The notice of intent also triggers an additional pleading requirement with adverse consequences if unsatisfied. When a party who submitted a notice of intent subsequently files a petition, the petition must identify on a map the location of any alleged environmental damage and include the results of any environmental testing performed on the property. It is important to note that the failure to include this information at the time of the filing of the judicial demand shall result in exclusion of this information.

Preliminary Dismissal

Defendants in legacy lawsuits often faced protracted litigation involving other parties and issues before getting information about their particular involvement with alleged contamination. Exceptions of vagueness seeking this information had varied levels of success, and some courts concluded that such information would be obtained in discovery.

To address this issue, a preliminary hearing was added to Act 312 to allow defendants to seek preliminary dismissal at the outset of a case. Within sixty (60) days of being served with a petition or amended petition, a defendant can request a preliminary hearing to determine whether good cause exists for maintaining the defendant as a party to the litigation. Unlike a vagueness exception, this is an evidentiary hearing. The plaintiff has the initial burden to introduce evidence to support the allegation of environmental damage. If this burden is carried, the moving defendant has the burden to demonstrate the absence of a material fact that it caused or is otherwise legally responsible, such as by contract, for the alleged environmental damage. Evidence may be introduced by affidavit or in written form and the rules governing summary judgments in the Code of Civil Procedure do not apply to the preliminary hearing.

The court is required to issue an order within fifteen (15) days after the preliminary hearing.

A defendant who obtains a preliminary dismissal is not necessarily out of the lawsuit. Dismissal is without prejudice. Any party can rejoin the dismissed defendant during the lawsuit if evidence is discovered that was not reasonably available at the time of the hearing on the motion for preliminary dismissal. However, if a dismissed party is not rejoined, that party is entitled to a judgment of dismissal with prejudice when a final nonappealable judgment is reached on the claims asserted. Prescription does not run when a preliminary dismissal is granted; a pleading rejoining a previously dismissed defendant relates back to the filing of the original petition or any amendments as provided by Code of Civil Procedure Article 1153.

A preliminary dismissal does not affect the remaining claims. It is without prejudice to any party’s rights to litigate the legal responsibility of any potentially responsible party, the allocation of responsibility among the potentially responsible parties, and any other issues incident to the finder of fact's determination of the party or parties who caused the damage or who are otherwise legally responsible for the alleged environmental damage. The procedure for a preliminary dismissal is in addition to the pretrial rights and the remedies available to the parties under the Code of Civil Procedure, including the right to discovery.

Environmental Management Orders

Code of Civil Procedure article 1552 is new. It creates a procedure for environmental management orders “EMO”’s) in legacy litigation. Upon the request of any party or the LDNR, the court will direct attorneys for the parties to appear before the court and develop an environmental management order to govern site inspections and environmental testing.

The EMO shall authorize all parties to access the allegedly impacted property for inspections and environmental testing. It shall also require each party to submit all test results to the other parties and LDNR within thirty days of receipt. In addition, the EMO shall include reasonable terms for all of the following:

Access to the property;
Investigation and environmental testing;
Sampling and testing protocols; and
Specific time frames within which to conduct such testing and sampling.

The EMO can also affect the admissibility of testing evidence. The failure of a party to provide results of testing to other parties under an EMO shall preclude the admission of those results in the litigation.

The EMO procedures provide a method for obtaining site access and ensuring that site testing will generate compatible data. When parties have unequal knowledge of alleged contamination or test data, they also ensures that all parties will have timely access to the property and data about environmental conditions. When large tracts of land are at issue, an EMO can help pinpoint the particular sites at issue. In addition, an EMO can prod the parties to complete site testing in a timely fashion so that contamination issues are defined earlier in litigation. Finally, it allows site access and testing rights for parties who otherwise would need regulatory action or other legal permission to access property.

Limited Admission of Environmental Liability

Code of Civil Procedure article 1563 is also new and creates a procedure for limited admission of environmental liability by defendants in legacy litigation. It allows a defendant to admit liability for the limited purpose of remediating all or a portion of environmental damage at issue. Upon admitting liability, the defendant becomes obligated to evaluate or remediate the environmental damage in accordance with the most feasible plan, which is developed in accordance with Act 312’s existing procedures for court approval of such a plan after obtaining a recommendation from LDNR. This change serves the public interest by allowing environmental damage to be promptly remediated to applicable regulatory standards rather than waiting until after trial or a settlement.

Several procedural requirements apply to the admission. It must be made in writing by filing the admission into the record of the litigation. Absent good cause shown, it must be made no later than ninety (90) days after the completion of environmental testing set forth in the EMO. An admission of limited liability by one party does not automatically extend to other parties. Instead, when a defendant files the first admission, the other defendants have sixty (60) days thereafter to file their own admissions of limited liability, provided that an additional admission also must be filed no later than the ninety day deadline for the original admission to be filed. In addition, a limited admission of liability does not establish primary jurisdiction for LDNR over the environmental damage.

When a limited admission is made, the court will follow Act 312’s existing procedures for the formulation of the most feasible plan for addressing the environmental damage with some modifications.

First, the court will make the reference to LDNR for a public hearing on the most feasible plan to evaluate or remediate environmental damage after the expiration of the ninety (90) day period for all defendants make a limited admission. Second, an admitting party remains obligated to pay LDNR’s costs for reviewing and formulating the most feasible plan, but it also is required to make an initial deposit of $100,000.00 with LDNR to cover these expenses prior to or with the submission of the party’s plan to LDNR. Any portion of the deposit that is not needed to pay expenses is returned to the admitting party.

Second, an admitting party becomes liable for the plaintiff’s investigation costs. Within thirty (30) days of LDNR’s filing of its recommended plan with the court, an admitting party shall reimburse plaintiff’s costs which the court determines to be recoverable under La. R.S. 30:29(E)(1). These expenses consist of a plaintiff’s costs of proving environmental damage. No provision is made in the event that the court does not make this determination within the thirty day period, either due to plaintiff’s failure to seek such a determination or other delays.

Third, a limited admission precludes another plan hearing later in the case. When a public hearing is held on the feasible plan in response to a limited admission, LDNR will not conduct an additional public hearing for the same environmental damage.

A limited admission of liability does not affect other claims against a defendant. It is not an admission of liability to the plaintiff for private damages or for remediation in excess of any applicable regulatory standards. It does not waive any rights or defenses of the admitting party. Likewise, it does not limit or restrict plaintiff’s claims for such relief.

However, the limited admission of liability does have an evidentiary effect. The limited admission, the plan approved by LDNR, and written comments on the plan provided by other agencies shall be admissible as evidence in any action.

Finally, a party who makes a limited admission waives some indemnity rights. By admitting limited liability, a party is deemed to waive any contractual rights against other persons for indemnity against punitive damages caused by the admitting party’s acts or omissions. If a claim for punitive damages arises from the acts or omissions of another person, the admitting party’s indemnity rights are not waived. Also, an admitting party’s waiver of indemnification against punitive damages does not apply to indemnification rights for any other claims or damages.

Remediation Standards

The amendments clarify that a defendant who is found liable shall submit a plan to evaluate or remediate the environmental damage to applicable “regulatory” standards, rather than simply “applicable standards.” In addition, LDNR shall use applicable “regulatory” standards in approving or structuring its most feasible plan recommendation.

Additional Agency Review of Plan

Under prior law, LDNR determined the most feasible plan with no requirement to seek input from other agencies. The amendments now require, in limited circumstances, an opportunity for other agencies to provide comments to LDNR as it formulates its recommended plan.

Within fifteen (15) days after making a preliminary structuring or approval of a plan that provides for an exception from LDNR’s regulatory standards or requires the application of regulatory standards of another agency, LDNR must submit the plan to the Louisiana Department of Agriculture and Forestry, the Louisiana Department of Environmental Quality, and the Department of Natural Resources for review and comment. Within thirty (30) days thereafter, each agency may provide written comments regarding the plan. Within thirty (30) days after the receipt of other agencies’ written comments, LDNR shall file the final plan with written reasons for its determination together with comments submitted by any other agencies in response to the plan.

An agency providing comments shall submit a schedule of its costs for the plan review to the court for reimbursement by the responsible party. However, comments are not required and the failure of an agency to respond to LDNR does not affect the validity of LDNR’s plan recommendation.

To assist in implementing this process, LDNR and agency heads are required to coordinate and establish a protocol to ensure inter-agency communication regarding plan development, timely delivery of all proposed plans to the appropriate agency heads, and timely receipt of all agency comments back to LDNR.

LDNR Plan-Related Discovery and Ex Parte Communications

Formerly, Act 312 had no explicit restrictions on discovery of LDNR personnel involved in formulating the agency’s feasible plan recommendation to the court. Litigation had ensued between parties and LDNR when such discovery was sought and courts had attempted to identify the appropriate scope and circumstances of such discovery.

In response, Act 312 was amended to add new provisions governing such discovery, as well as subpoena power. Any party may subpoena representatives, personnel, and contractors involved in the formulation of a feasible plan of LDNR, as well as agencies who provide comments regarding the plan, for deposition or trial. However, parties are now prohibited from obtaining discovery regarding LDNR’s review, approval, or structuring of the feasible plan, and discovery of the same from an agency that reviews and provides comments on the plan, until LDNR has submitted its final, feasible plan recommendation with reasons to the court. When a party issues a subpoena for a deposition or documents to LDNR, it must pay the LDNR’s costs to respond.

In a related amendment, parties are also prohibited from having any ex parte communication with any employee, contractor, or representative of LDNR or any other agency involved in the formation of a feasible plan, regarding the formation of the plan, from the date the responsible party or parties submit a plan to LDNR until after LDNR has filed its approved feasible plan with the court. To verify such communications have not occurred, LDNR and any other agency involved in the plan formulation are required to submit an affidavit of compliance with this restriction with the submission of the recommended plan to the court.

Compliance Orders

Currently, La. R. S. 30:29.B(2) states that Act 312 does not affect the enforcement powers and authority of LDNR. However, a recent decision stayed LDNR from enforcing a compliance order while litigation was pending, thereby allowing the existence of private litigation to trump the public’s interest in remediation and regulatory compliance.

The amendments address this issue by reaffirming LDNR’s enforcement authority. Based on its findings, LDNR may issue any compliance order it deems necessary to either the operator of record or, where applicable, a party found responsible or admitting responsibility for implementing the most feasible plan. If a compliance order is issued against the responsible party who is not the current operator of record, the responsible party shall give the current operator of record notice of the compliance order within thirty days of the responsible party's receipt of the compliance order.

Effective Date

House Bill 618 and Senate Bill 555 shall not apply to any case in which the court issued or signed an order setting the case for trial on or before May 15, 2012, regardless of whether such trial setting is continued.

CONCLUSION

The modifications to Act 312 are largely intended to expedite the identification and remediation of environmental damage. New procedures provide for a prompt determination of the basis for claims in Act 312 cases, a limited admission of liability to allow prompt remediation of contamination, more robust agency review of remediation plans, and appropriate delineation of contamination at the commencement of litigation with a suspension of prescription to allow plaintiffs adequate time to obtain evidence of environmental damage before suit is filed. Ultimately, these revisions should streamline legacy cases and allow remediation under Act 312 to be performed efficiently consistent with the public interest in a clean environment.

QUESTIONS? Contact Mr. McNeal at rbmcneal@liskow.com.

Rob McNeal is a shareholder in Liskow & Lewis’ New Orleans office. His practice includes environmental, employment, commercial, and tort matters. In addition, he advises clients regarding energy and environmental regulatory matters. Mr. McNeal has been practicing law since 1984 and is an experienced litigator who has tried cases concerning the cleanup of legacy oilfield properties, class actions, environmental citizen suits, refinery-related litigation, pipeline matters, oil and gas disputes, landfill suits, and commercial litigation. Several national publications, including Chambers USA, The Best Lawyers in America, and Louisiana Super Lawyers have recognized Mr. McNeal as a leader in his field. Mr. McNeal received his LL.M. in Energy/Environmental Law, with distinction, from Tulane University Law School in 1993. He also received his J.D., cum laude, from Tulane University Law School in 1984.

EPA Issues New Air Regulations for the Oil and Natural Gas Industry

Kelly Becker — Fri, 20 Apr 2012 08:46:25 -0500

By Stephen Wiegand

On April 17, 2012, the United States Environmental Protection Agency (EPA) finalized New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) for natural gas wells that are hydraulically fractured.

The rule aims to reduce levels of volatile organic compounds (VOCs) released during well completion. Prior to January 1, 2015, operators may use flaring to reduce such emissions. Beginning January 1, 2015, however, operators must reduce emissions by installing equipment that captures natural gas during completion and makes it available for use or sale.

The rule also establishes new notification and reporting requirements for well completions. It requires that owners or operators of hydraulically fractured and refractured natural gas wells notify EPA by e-mail no later than two days before completion work begins. Additionally, each year owners or operators must submit a report on their well completions that is certified by a senior company official attesting to the report’s truth, accuracy, and completeness.

The rule retains existing NESHAP standards for large glycol dehydrators at well sites and also sets new NESHAP standards for small glycol dehydrators (ones with an annual average natural gas throughput of less than 85,000 standard cubic meters per day, or actual annual average benzene emissions of less than 1 ton per year). Small dehydrators must meet a unit-specific limit for emissions of BTEX (benzene, toluene, ethylbenzene, xylene) that is based on the unit’s natural gas throughput and gas composition.

In addition to the new standards for hydraulically fractured wells, the rule also updated existing standards for natural gas processing plants, storage tanks, and transmission lines.

For more information, see www.epa.gov/airquality/oilandgas/actions.html

Supreme Court of Texas Revises Opinion in Pipeline Common-Carrier Case

Robert Theriot — Thu, 12 Apr 2012 14:48:13 -0500

By Carlos Moreno:

The Supreme Court of Texas recently delivered a revised opinion discussing the power of eminent domain exercised by a common carrier CO2 pipeline. In Texas Rice Land Partners, LTD v. Denbury Green Pipeline-Texas, LLC, No. 09-0901, 2012 Tex. LEXIS 187 (Tex. Mar. 2, 2012), the Court was asked if a landowner can challenge in court the eminent domain power of a CO₂ pipeline owner with a common carrier permit from the Railroad Commission of Texas (“RRC”). The Court decided in favor of the landowner.

Denbury Green Pipeline-Texas LLC, a subsidiary of Denbury Resources, applied with the RRC for a permit to build and operate a CO₂ pipeline in Texas. Denbury Green noted in its permit application that the CO₂ pipeline would be operated as a “common carrier”, and indicated that the gas would be “owned by others, but transported for a fee.” Denbury Resources had plans to purchase CO₂ from third parties in the future, but the immediate plans were to only transport CO₂ owned by Denbury Resources. The RRC approved the permit, including common carrier status. Denbury Green then attempted to condemn a pipeline easement from land owned by Texas Rice Land Partners, Ltd. (“Texas Rice”). However, Texas Rice refused entry. Litigation ensued, with the lower courts finding in favor of Denbury Green.

The Court began its discussion by examining the power of eminent domain in Texas. The Court noted that Texas law prohibits the taking of property for private use, and requires just compensation for public use takings. The Legislature can grant eminent-domain power, but if the statute leaves doubts about its scope, the Court held that the statute will be strictly construed in favor of the owner of the condemned land.

At the outset, the Court also had to determine whether the Commission’s common-carrier finding could be challenged in court. The Court first noted that the statute does not state that the Commission’s decision to grant a common-carrier permit is conclusive and unreviewable by the courts. In addition, the Court described the process to obtain common-carrier status from the RRC as “one of registration, not of application” with no adjudication, notice, or hearing. Texas Rice, at *18. The Court found that this process by itself failed to meet constitutional requirements.

Finding that the landowner could judicially challenge the eminent domain finding, the Court then determined what the proper judicial test for common-carrier status should be. To be a common carrier, the Court said, the pipeline must serve the public and not just the pipeline owner or its affiliates. Denbury Green argued that making the pipeline available for public use is sufficient to obtain common-carrier status. The Court found this interpretation to be inconsistent with the statutory language. In addition, the Court found that merely stating that the pipeline is available for public use could allow a carrier to obtain eminent domain powers even if it knows that no other party would ever desire to use the pipeline.

However, the Court went further and said that “a carrier is not a common carrier if it transports gas only for its own consumption.” Thus the Court found that even if Denbury buys CO₂ gas from third parties, common carrier status is not proven if after transportation all the CO₂ is then used by the owner of the pipeline. Therefore, in order to be a common carrier, some of the CO₂ being transported must be owned by a third party (not including subsidiaries of the pipeline owner), then either retained by the third party or sold to a party other than the carrier or its affiliates.

The Court held that for a CO₂ pipeline carrier to qualify as a common carrier, “a reasonable probability must exist that the pipeline will at some point after construction serve the public by transporting gas for one or more customers who will either retain ownership of the gas or sell it to parties other than the carrier.” Texas Rice, at *26. A granted common-carrier permit will still be prima facie valid, but a landowner can challenge it in court. If there is a judicial challenge, the pipeline company would have to burden to prove that it is indeed a common carrier before it can exercise the power of eminent domain.

In the case at bar, the Court found that Denbury Green did not meet the requirements for common-carrier status as a matter of law. The evidence showing that Denbury could be transporting CO₂ from third parties was not enough to show a reasonable probability. Even if Denbury transported CO₂ from third parties, its intention was to use all the CO₂ in Denbury’s oil fields for tertiary recovery. Thus, Denbury would be the only end user of the CO₂, making it a private carrier.

The Court explicitly stated that its opinion is limited common-carrier status for pipelines transporting CO₂ or hydrogen gas under Section 111.002(6). However, if the reasoning were extended in the future to other pipeline operations, common-carrier status would require companies to not only transport products other than its own, but also have one or more third-party end users after pipeline transportation.

EPA Proposes Significant Changes to NPDES Permit for Oil and Gas Facilities in the GOM OCS

Robert Theriot — Thu, 12 Apr 2012 14:41:58 -0500

By Carlos J. Moreno

On March 7, 2012, the Environmental Protection Agency (“EPA”) published in the Federal Register a proposed 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 “proposed permit”). See 77 Fed. Reg. 13601 (Mar. 7, 2012), available at http://www.epa.gov/region6/water/npdes/genpermit/index.htm. Affected companies may wish to comment on proposed changes to the permitting and reporting process, and to the effluent limitation and monitoring requirements. Comments are due by May 7,2012. Some of the most significant proposed changes are described below.

Notice of Intent and Discharge Monitoring Reports

Under the proposed permit, any party that meets one of the following criteria would need to obtain coverage as an “operator”: (1) possession of lease block and operational control over activities, (2) day-to-day operational control of activities necessary to ensure compliance with the permit, or (3) operational control over a vessel or Mobile Offshore Drilling Unit (“MODU”) subject to Cooling Water Intake Structures (“CWIS”) regulations. As for Discharge Monitoring Reports (“DMRs”), the proposed permit states that “monitoring results for each facility within the particular lease block shall be reported on DMRs for each individual outfall authorized that has a monitoring requirement.” Proposed Permit, at p. 52 (emphasis added). This language suggests a potential need for separate permit coverage for any MODU subject to CWIS requirements.

Effluent Limitations and Monitoring

The proposed permit includes new effluent limitations and monitoring requirements for specific discharges, as well as a number of clarifications about the authorization status of specific waste streams. For example:

· Operators must conduct a Produced Water Characterization Study (individual or joint study);

· All hydrate control fluid discharges now require toxicity testing;

· Facilities subject to CWIS requirements must submit a CWIS-specific quarterly report;

· Operators should implement spill prevention Best Management Practices (“BMPs”);

· Propping agents used in hydraulic fracturing are considered to be produced sand; and

· Fluids used for testing fluid handling equipment cannot be discharged.

The public comments period runs until May 7, 2012. EPA will be holding two public hearings on the proposed permit: April 11 in Houston, Texas and April 12 in Metairie, Louisiana.

Fifth Circuit holds purchase and sales agreement complies with Statute of Frauds

Robert Theriot — Mon, 20 Feb 2012 17:53:43 -0500

By Joanna Nelson:

Preston Exploration Co., L.P. v. GSF, L.L.C., Cause No. 10-20599, 2012 U.S. App. LEXIS 1873 (5th Cir. Tex. Feb. 1, 2012)

The Fifth Circuit recently vacated a judgment in the U.S. District Court for the Southern District of Texas, holding that the lower court had improperly conflated “two distinct principles – whether parties come to a meeting of the minds as to the subject matter of a contract with whether a writing’s legal description is sufficient to meet the statute of frauds.” Preston Exploration Co., L.P. v. GSF, L.L.C., Cause No. 10-20599, 2012 U.S. App. LEXIS 1873, *12 (5th Cir. Tex. Feb. 1, 2012). The parties’ dispute involved uncompleted exhibits to three Purchase and Sales Agreements (“PSAs”) entered into for the sale/purchase of certain oil and gas leases. Id. at *2. The exhibits, which were specifically referenced and incorporated into the PSAs, included a document “describing oil & gas leases to be conveyed and a reference to a different exhibit as the document setting out the form of the assignments to be delivered at closing. Id. at *4. The Seller, who had executed all three PSAs without complaint despite the PSAs providing for payment of a non-refundable deposit that amounted to $11 million, ultimately refused to close on the sale. Id. This suit followed.
After a three-day bench trial, the District Court determined that exhibits to the PSAs “did not contain enough information to be statute of frauds compliant” and that “the exhibits were not finalized at the time the PSAs were executing . . . [and thus] could not be incorporated into the PSAs.” Id. at *5. Without the exhibits, the District Court held that PSAs were not enforceable because they did not furnish “the means or data by which to identify the leases to be conveyed with reasonable certainty.” Id. at *5-6. The District Court also held that the Seller was not entitled to a return of the $11 million down payment, which holding was not challenged on appeal. Id. at *6.
The Fifth Circuit disagreed with the District Court on enforceability because “the PSAs do contain some indication of what is to be conveyed . . . [and] specifically provide that [Seller] is to convey all of Seller’s right, title and interest in and to all oil and gas leases as defined in Exhibit A.” Id. at *9-10. Internal quotes and brackets omitted. The Fifth Circuit noted that the “assignment documents could not be final at the signing of the PSAs because it was clearly intended by the parties that title work remained to be completed” and that the “PSAs specifically include provisions for curing title defects and for adjusting the contract price for any title defects which could not be cured.” Id. at *11. The “PSAs clearly reflect the intention of the parties and a recognition that there was still some title work to be done before a final determination could be made as to the leases which would ultimately be conveyed.” Id. The District Court thus “misconstrued this lack of finality as to the assignment documents as evidence that there was no meeting of the minds as to the subject of the contract.” Id. at *11-12. If, however, there had been no meeting of the minds, “there would be no contract whatsoever and the statute of frauds issue would be moot.” Id. at *12.
Because the intentions of the parties were clear by the terms of the PSAs and the “attached exhibits were all part of the same transaction and should be construed together,” the lack of finality of the exhibits did not prevent their consideration as part of the contracts to convey the property. Id. at *14-15. Though limiting enforcement of the PSAs to “those leases identified by recording information,” the Fifth Circuit held that the Buyer “may obtain specific performance” of the PSAs and remanded the case for “proceedings consistent with this opinion.” Id. at *15-16.

Texas case holds seller bound to terms of forged document

Robert Theriot — Wed, 08 Feb 2012 15:55:50 -0500

By James T. Kittrell

The Texas Court of Appeals for the Eleventh District of Eastland has recently held that a seller of an oil and gas property may be held to the terms of a forged purchase agreement if the seller properly signs an assignment that specifically incorporates the terms of the forged document. Raven Resources, LLC v. Legacy Reserves Operating, LP, No. 11-09-00348-CV, 2012 Tex. App. LEXIS 310, (Tex. App. Eastland, Jan. 12, 2012).

Raven Resources (“Raven”) was interested in selling certain oil and gas related-properties to Legacy Reserves Operating LP, (“Legacy”). Raven employed Michael Lee as its primary contact in negotiations with Legacy over the sale of the property involved in the case. After a negotiation period, Legacy sent a draft of a purchase agreement to Raven. The document was dated June 22, 2007 and it was not signed. The draft purchase agreement did not describe the property in question, but did state that the purchase price was $26.626,000. Id. at *2 David Stewart, Raven’s sole managing member, signed the draft purchase agreement and sent it to Legacy. While Stewart thought this concluded the negotiation of the agreement, Legacy continued to conduct its own due diligence, and ultimately came to the conclusion that certain revisions to the draft purchase agreement were required. Id. Among those revisions was a reduction in the purchase price to $20,300,000. These changes were reflected in another purchase agreement, this one dated July 11,2007, which was sent from Legacy to Lee. At this point, Lee failed to tell Stewart about the agreement and forged Stewart’s signature to the document and returned it to Legacy. Id. at *2-3 The record indicated that only David Stewart had the authority to bind Raven to any agreement.

The two sides closed the transaction by mail, in which Raven transferred the various interests and properties included in the July 11 agreement via thirty-five “assignments and bills of sale” dated August 3, 2007. These assignments specifically incorporated the terms of the July 11 agreement. Id. at *3 Several weeks later, Raven discovered the discrepancy between the price included in the June 22 draft agreement and the amount Legacy had actually paid Raven, which was the amount of the July 11 agreement. Raven then filed a lawsuit against Legacy, and Legacy filed counterclaims against Raven. Both sides moved for partial summary judgment, and the trial court granted Legacy’s motion, entered a take-nothing judgment against Raven, and severed Legacy’s remaining counterclaims to create a final ,appealable judgment. The court did not give a reason for its decision to grant the summary judgment motion. Id. at *5

On appeal, Raven claimed that the trial court erred in granting summary judgment because the July 11 agreement was forged, and thus void as a matter of law. Legacy responded by noting that the terms of the July 11 agreement were properly incorporated into the assignments, which were legal and enforceable. Id. at *6 Originally, the court of appeals issued an opinion overturning the grant of summary judgment for Legacy. However, the court granted Legacy’s motion for rehearing and withdrew its former opinion. Id. at *1 Ultimately, the court of appeals affirmed the trial court. It found that while the July 11 agreement itself was forged, and thus invalid, the incorporation was still effective. Id. at *8 The opinion noted that while a reference to a void agreement references nothing, the assignments in question did more than simply mention the July 11 agreement. Instead, by incorporating the terms of that agreement, the parties had made the actual language a part of the content of the assignment. Id. at *9 Thus, those terms, which include the sale price, are treated as equal to any other language in the assignment, regardless of whether or not the original July 11 agreement was void. Since the assignments themselves were valid, the court of appeals upheld the grant of summary judgment. Finally, the court rejected Raven’s argument that the assignments could be rescinded because of a mutual mistake as to price. Id. at *10-11 Noting that a party is presumed to know the contents of any document it signs, the court rejected Raven’s claims, holding that based on an objective standard, there was not enough evidence to indicate mutual mistake.

Update to the December 20, 2011 Liskow & Lewis E-Newsletter

Kelly Becker — Mon, 09 Jan 2012 10:34:16 -0500

By Megan Spencer

In our December 20, 2011 E-Newsletter, we reported on the status of: (1) EPA’s Cross-State Air Pollution Rule; and (2) the EPA Inspector General’s report, “EPA Must Improve Oversight of State Enforcement.” Some recent developments in those areas merit an update:

(1) On December 30, 2011, the United States Court of Appeals for the D.C. Circuit stayed EPA’s Cross-State Air Pollution Rule (CSAPR). The Court stayed CSAPR until it could resolve the petitions for review. In the meantime, EPA will continue to administer the Clean Air Interstate Rule. Click here for the complete ruling (PDF).

(2) Peggy Hatch, Secretary of the Louisiana Department of Environmental Quality (LDEQ), sent a response letter to the Inspector General of the EPA responding to the publication of EPA’s report, entitled “EPA Must Improve Oversight of State Enforcement.” The purpose of the response letter was to highlight some of the errors and omissions in the report criticizing Louisiana’s enforcement record. In her response, Secretary Hatch identified 14,454 enforcement actions that EPA did not take into account in evaluating the LDEQ’s enforcement record, and stated that Louisiana has seen tremendous improvement in ambient air and water quality in the recent past. Click here for the complete ruling (PDF).