Archive for the ‘Air Pollution’ Category
Tuesday, September 25th, 2012
In United States v. La. Generating, LLC, 2012 U.S. Dist. LEXIS 134195 (M.D. La. 9/19/12), a federal district court ruled that reheater replacement projects for a coal-fired power plant did not qualify for the Routine Maintenance, Repair and Replacement (RMRR) exception to the New Source Review (NSR) program.
As a result, the defendant who acquired the coal plant pursuant to a 363 bankruptcy sale will now be liable for pre-acquisition NSR violations. This is because the court previously ruled that the defendant was the successor to the prior plant owner notwithstanding the “free and clear” language of the order of the bankruptcy court approving the sale as well as the confirmation order providing that the defendant was not a successor and “shall not have any liability for any claims against [Cajun Electric] as a result o fit s purchase of the Acquired Assets.” See December 2011 for our discussion on that ruling.
In this case, the Cajun Electric Power Cooperative (Cajun Electric) began constructing the “Big Cajun II” (BCII) coal-fired power plant in 1976 and began operating the plant in 1981. In 1994 and 1995, Cajun Electric upgraded the turbines of Units 1 and 2 (“the 1994/95 work”). Cajun Electric did not obtain a Preventing of Significant Deterioration (PSD) permit prior to starting work. In 1998 and 1999, Cajun Electric replaced portions of the primary boiler reheaters (“the 1998/99 work”) also without obtaining a PSD permit. The cost of each project was estimated at $4.5 million.
Defendant LaGen acquired BCII in April 2000 pursuant to the bankruptcy sale. In September 2001, LaGen submitted a revised Title V permit. While the application was still pending, EPA issued a notice of violation (“NOV”) regarding the 1998/99 work. In 2009, the federal government filed a lawsuit against LaGen seeking civil penalties and injunctive relief for NSR-PSD and Title V permit violations. Following the December 2011 decision, the parties then filed motions for summary judgment on whether the replacement of the primary reheaters constituted “major modifications” that triggered NSR-PSD.
The parties agreed that the so-called WEPCO factors set forth in Wisconsin Electric Power Co., v. Reilly, 893 F.2d 901 (7th Cir. 1990) should be used to determine if the two primary reheater replacement projects constituted RMRR. The WEPCO factors are the nature, extent, purpose, frequency, and cost of the work, with no individual factor being dispositive. For the “frequency” factor, the parties agreed the court should take into consider the work conducted at the particular unit, the work conducted by others in the industry, and the work conducted at other individual units within the industry. In evaluating the “frequency” factor, the court said the relevant industrial sector was the coal-fired electric generating facilities but that it would give more weight to the frequency of similar work at particular units than to the overall number of similar projects across the industry.
The court said that just because other places may be replacing primary reheaters does not make it routine. However, if it were to turn out that similar units tended to replace their primary reheaters multiple times during a unit’s lifetime, this would suggest that such a project was routine. The court also said that LaGen had the burden to establish the applicability of the exclusion.
On the “nature” factor, the defendant had argued that it followed both company protocol and general industry practice before doing the work, the work was routine. However, court said the degree of planning suggested that the work was anything but routine. The court also was persuaded that the work was not maintenance because Cajun Electric had treated the costs of the work as capital expenditures.
On the “extent” factor, the court said the issue was basically the size and scope of the project. LaGen pointed out that the work the work was done in 25 days per unit, a relatively short period of time within the industry. LaGen makes also noted that Cajun Electric directed bidders that the work was not to change the thermal performance of the reheater and that the new reheaters were to function in the same way. In addition to the extensive planning and preparation for the projects, the government pointed out that Cajun Electric’s own work order system referred to projects under $50,000 as “routine maintenance”. The Court noted that the work took 25 days per unit to complete, required a rail and pulley system to remove the old tubing, and the use of 175 boilermakers. Everything about the project, the court concluded, was that it was extensive project and not a routine project.
Turning to the “purpose” factor, the court said the RMRR exception meant to apply to work that was done to preserve the status quo of a unit. The court noted that the purpose of the work was to reduce the number of forced outages that had been increasing over the years due to tube failures. The court said the work was to improve the condition of the units. Since this type of work was beyond the purpose of the RMRR exception, the court found that the factor weighed against applying the exception.
For the “frequency” factor, LaGen pointed to projects that had replaced all or significant portions of reheaters at 574 units in the industry. The government argued this universe was too broad because it included projects costing at least $100,000 even though the cost for each of the Cajun Electric replacements was $4.5MM. The government argued the relevant projects should be those that occurred prior to 1998 and that cost at least $4.5MM. The court agreed that similar projects within the industry must be same size and scope, and that only pre-1998 projects were relevant. Even if it used the larger universe suggested by LaGen, the court said, there were no projects between 1972 and 1998 where facilities had performed multiple reheater replacements. Accordingly, the court concluded that the work was not a frequently performed procedure.
Turning to the cost factor, the court said $4.5MM was not only a lot of money but the most Cajun Electric had ever spent on the units. Borrowing from the definition of modification under the New Source Performance Standards, the defendant argued any project costing less than half of the replacement cost for an entire boiler should be considered routine. However, the court said such an interpretation would be an exception that swallowed the rule and did not fit with the narrow nature of the exception.
Saturday, September 8th, 2012
New York City enjoyed classic fall weather last week with cloudless skies and crisp temperatures. Depending on how high your office or apartment was located, you could see all the way down to New York Harbor, see Yankee Stadium in the Bronx or Citifield where the Mets play. On days like these, it is hard to remember how bad the environmental in New York was in the 1970s.
Fortunately, EPA had the foresight to hire freelance photographers to capture images relating to environmental problems and everyday life in the between 1971-1977 in a project called Documerica. The National Archives has digitized much of this project and more than 15,000 images are available from the Archival Research Catalog (ARC). Visitors can search by location, media or type of pollution. Click Documerica to travel back in time to literally another world.
For my law school class, I cobbled together pictures showing the common environmental conditions we faced in New York City during the 1970s. NYC in 1970s. You can literally breathe a sigh of relief and appreciate how far we have come in the past 40 years.
The New York Times has recently discovered the Documerica Series
Tuesday, August 28th, 2012
The dog days of August have been particularly cruel to EPA and law professors who are teaching administrative law this semester. In August alone, there separate federal appeals court vacated high profile Clean Air Act initiatives of EPA. The decisions were stunning for their lack of deference to EPA’s interpretations of its Clean Air Act authority. As a result of these decisions, administrative law professors are going to have to revise their course materials to incorporate these rulings.
Judicial challenges to administrative actions are guided by the principles articulated by the United States Supreme Court in Chevron, U.S.A., Inc. v. NRDC, Inc., 467 U.S. 837 (1984). In Chevron, the Supreme Court set forth a two-step analysis for reviewing administrative decisions. Step 1 is whether Congress has directly spoken to the precise question at issue. If the intent of Congress is clear, the court as well as the agency must give effect to the unambiguously expressed intent of Congress. Step 2 applies when the statute is silent or ambiguous with respect to the specific issue. Under such a situation, the court is not to impose its own construction of the statute but afford considerable weight to the interpretation of the statutory scheme by the agency that has been entrusted to administer the law. The court may not substitute its own construction of a statutory provision and should defer to a reasonable interpretation made by an agency unless the interpretation or regulation is arbitrary, capricious, or manifestly contrary to the statute. The court explained that when a challenge centers on the wisdom of the agency’s policy rather than whether it is a reasonable choice within a gap left open by Congress, the challenge must fail. The court said that under our form of Constitutional government, federal judges have a duty to respect legitimate policy choices made by the other branches of the government. The court said it was not the responsibility or role of he courts to assess the wisdom of policy choices or resolve the struggle between competing views of the public interest.
The issue in Summit Petroleum Corp. v. EPA, 2012 U.S. App. LEXIS 16345 (6th Cir. 8/7/2012) was if EPA could treat geographically distant gas production wells as one emission source so that the entire production system would be considered a “major source” that was subject to the Title V permit program. A “major” source under Title V is “any stationary facility or source of air pollutants which directly emits, or has the potential to emit, one hundred tons per year of any pollutant,”
In this case, the plaintiff owned natural gas sweetening plant that processed “sour” gas produced from approximately 100 production wells in a 43-square mile area. The distance from the wells to the sweetening plant varied from 500 feet to 8 miles. Summit Petroleum owned all of the production wells and the subsurface pipelines that connect each of the wells to the sweetening plant. However,Summit did not own the property between the individual well sites or the property between the wells and the plant. None of the well sites shared a common boundary with each other nor did any of the well sites share a common boundary with Summit’s production plant. Flares were installed at various points on the pipelines to relieve pressure on the gas collection equipment. The closest flare was located approximately one half-mile from the plant while the remaining flares were each over one mile away.
The sweetening plant, gas production wells, and flares emit sulfur dioxides (SO2) and nitrous oxides (NOx). Because the sweetener plant emitted or had the potential to emit less than 100 tons per year of these pollutants, it would not be regulated as a “major source” Title V of the Clean Air Act (CAA). However, when if SO2 emissions of the flares and wells were combined with those of the sweetening plant, the total SO2 emissions would exceed the 100 tons threshold. EPA’s Title V regulations provide that multiple pollutant-emitting activities can be aggregated together and considered a single stationary source only if they: (1) are under common control; (2) “are located on one or more contiguous or adjacent properties”; and (3) belong to the same major industrial grouping (40 CFR 71.2).
In 2005,Summit and the Michigan Department of Environmental Quality (MDEQ), submitted a request to the EPA to determine ifSummit’s facilities met the definition of a Title V major source.Summit argued that aggregation was improper its wells were located at great distances from its production facility on entirely different tracts and leases so that they should not be considered contiguous or adjacent to one another. Summit also noted that EPA specifically considered aggregation of multiple facilities in the oil and gas industry under the Hazardous Air Pollutant (HAP) regulations and determined that aggregation was improper.
EPA determined that the natural gas sweetening plant and the production wells constituted a single stationary source and was a major source that required a Title V permit. The agency said that the wells and production plant were commonly owned, part of the same industrial grouping but were not located on contiguous surface sites. Accordingly, EPA said it had to evaluate the adjacency of the sour gas wells to the sweetening plant to determine whether Summit’s facilities constituted a single stationary source for purpose of the Title V program. Although the agency acknowledged that its so-called “Wehrum Memorandum” stated that “proximity is the most informative factor in making a source determination involving oil and gas activities”, EPA concluded the wells and sweetening plant based on a “common sense notion of a source and the functional interrelationship of the facilities.”
Summit appealed, arguing that the “adjacency” can be established through functional relatedness was unreasonable and contrary to the plain meaning of the term “adjacent.” In a 2-1 decision, the 6th circuit agreed, vacating EPA’s ruling and remanding the matter to determine if the sweetening plant and gas wells were sufficiently physically proximate to be considered “adjacent” within the ordinary, i.e., physical and geographical, meaning of that requirement.
EPA argue it was entitled to Chevron deference since had an established history of used functional relatedness to supplement the traditional definition of “adjacent”. However, the court held that the term “adjacent” was unambiguous and it was not required to defer to EPA’s interpretation. The court said just because an agency had adopted a long-term erroneous interpretation did not mean the agency was entitled to deferential treatment. Instead, the court said that it would take this first opportunity to review a history of “entrenched executive error” to vacate EPA’s agency’s unreasonable interpretation of its Title V permitting plan. Ouch!
Even if the term was ambiguous, the court said it would still find the EPA’s interpretation of “contiguous or adjacent properties” was inconsistent with the regulatory history of its Title V permitting plan and the agency’s own guidance memorandums. The court noted that the Wehrum Memorandum had rejected the notion that geographically distant oil and natural gas activities could be considered “contiguous” or “adjacent. Moreover, even when the Obama Administration withdrew the Wehrum Memorandum and replaced it with the so-called the McCarthy Memorandum, the court said EPA conceded that proximity may well be the determining factor.
State of Texas v. United States EPA, 2012 U.S. App. LEXIS 16898 (5th Cir. 8/13/2012) involved EPA’s disapproval of a revision to the Texas State Implementation Plan (SIP). EPA has been engaged in a highly public dispute with Texas over its administration of the CAA and has threatened to rescind the state’s CAA delegation. It appears that the court may have viewed the challenged action in this case as more a reflection of this political battle rather than a reasoned policy dispute.
In the 1990s,Texas implemented a Flexible Permit Program (FPP) for new source review (NSR) for minor sources. Under the FPP, a facility could obtain a permit that would allow modifications to facilities without additional regulatory review as long as the emissions increase would not exceed an aggregate limit specified in the permit. The FPP was intended to incentivize grandfathered facilities to install pollution controls in exchange in exchange for obtaining approval of modifications or operational changes to emissions sources. All told, approximately 140 FPP permits were issued.
Texas submitted included its FPP in revisions to its SIP in 1998 as a form of Minor New Source Review (NSR). In 2007, EPA began sending letters to FPP facilities indicating that the permit may not comply with applicable federal requirements. EPA also began objecting to Title V permits issued to facilities with FPP permits.
In 2009, EPA proposed to disapprove the revision because it was not expressly limited to Minor NSR. EPA was concerned that the program could be used by major sources to avoid undergoing NSR. EPA wanted an express negative statement prohibiting major sources from avoiding Major NSR. In 2010, EPA finalized its objection to the SIP revision. By the time the dispute reached the court, 42 facilities had begun the process of “de-flexing” or withdrawing their FPP permits.
The court said that EPA’s quibbling with the language of the program was inconsistent with the notion of cooperative federalism envisioned in the CAA. The court said that while EPA was responsible for providing the basic requirements of state implementation plans, the states had broad authority to determine the methods and particular control strategies they will use to achieve the statutory requirements. The court said EPA did not have authority to condition approval of a SIP based simply on its preference of a particular control measure.
The court also found that EPA had failed to put forth evidence demonstrating how the program would cause interference with applicable air quality standards. In the absence of any expression of technical expertise, the court said it did not defer to EPA’s interpretation. The court held that the CAA furnished the standards that EPA was to apply in disapproving SIP revisions and those standards did not require drafting in negative terms. Therefore, the court held that this first reason for rejecting the Texas Program was arbitrary and capricious, and in excess of its statutory authority.
EPA also claimed that the FPP contain inadequate monitoring, record keeping and recording (MRR) provisions but instead conferred too much discretion on the TCEQ Director. EPA alleged it had a policy disfavoring such director discretion, the court rejected this ground as well. The court said that EPA did not cite its policy against director discretion when it disapproved the FPP so the court did not have to consider that policy. However, the court observed that the agency had approved such provisions in other state SIPs. The court said that while EPA could certainly change its policies, it could reject the very concept of director discretion in one case months after approving extensive director discretion in another, and then hold out its rejection here as an example of reasoned decision-making. This suggested to the court that EPA had invented this policy for the sole purpose of disapproving Texas’s proposal. Ouch again! As a result, the court vacated EPA’s disapproval and remanded the SIP revision to EPA for reconsideration.
In Eme Homer City v. EPA, 2012 U.S. App. LEXIS 17535 (D.C. Cir. 8/21/2012), the Court of Appeals for the District of Columbia struck down the Cross-State Air Pollution Rule (Transport Rule) which is also know as the “good neighbor” provision. Under section 110 of the CAA, SIPs must contain provisions that prevent emissions of pollutants that will “contribute significantly to non-attainment or interference with maintenance of air quality standards.”
The court held that EPA exceeded its authority when it promulgated the Transport Rule because upwind States were required to reduce emissions by more than their own significant contributions to a downwind State’s non-attainment and did not take into account from other upwind States, The court said the Transport Rule was flawed because the emissions reductions for each upwind State was not tied to how much the upwind State contributed to downwind States’ air pollution problems but instead on the cost to reduce emissions if the upwind State’s plants applied all controls available at or below a given cost per ton of pollution. In addition, the court said EPA violated the CAA when it failed to require reductions on a proportional basis that took into account contributions of other upwind States to the downwind States’ non-attainment problems. The court said that EPA may not require upwind States to do more than necessary for the downwind States to achieve the NAAQS.
The court also held that EPA acted improperly when it simultaneously issued Federal Implementation Plans (FIPs) to implement emission reductions obligations on sources in the upwind States instead of providing states an initial opportunity to implement the obligations themselves through their own SIPs. The court said EPA cannot impose a FIPs until the agency finds that the SIP fails to contain a “required submission” or EPA disapproves a SIP because of a deficiency. However, the court said, EPA could deem that a SIP lacked a required submission or was deemed deficient for failing to implement the good neighbor obligation at the same time that EPA adopted the good neighbor provision. The court said that the placement of the good neighbor requirement in the SIP section of the CAA strongly suggested that Congress intended states to implement those obligations.
The court said that the good neighbor provision was not a free-standing tool for EPA to seek to achieve air quality levels in downwind States that are well below the NAAQS. Therefore, if modeling shows that a given slate of upwind reductions would yield more downwind air quality benefits than necessary for downwind areas to attain the NAAQS, EPA must attempt to ratchet back the upwind States’ obligations to the level of reductions necessary and sufficient to produce attainment in the downwind States
Moreover, the court noted, section 126 of the CAA explicitly authorized EPA to take direct action including “emission limitations and compliance schedules,” against specific sources that generate interstate pollution. The fact that Congress explicitly authorized EPA to use direct federal regulation to address interstate pollution suggests it did not contemplate direct Federal regulation in the section 110 of the CAA.
The summer was not a complete loss for EPA as EPA was able to win another battle with Texas in Luminant Generation Co. LLC v. United States EPA, 2012 U.S. App. LEXIS 15722 (5th Cir. 7/12/2012). Here, EPA partially approved a portion of SIP revision submitted by Texas that created an affirmative defense against civil penalties for excess emissions during unplanned startup, shutdown, and maintenance/malfunction (“SSM”) events. EPA explained that it had long recognized that sources may, despite good practices, be unable to meet emission limitations during periods of start-up and shutdown and that sources may suffer a malfunction despite good operating practices due to events beyond the control of the owner or operator. A source has the burden of proving that the excess emissions were due to circumstances beyond the control of the operator or the owner.
However, the agency disapproved the portion of the SIP revision providing an affirmative defense against civil penalties for planned SSM events EPA said that sources should be able to comply with applicable emission limits for planned events. The EPA said that the affirmative defense for planned SSM events was not “narrowly tailored” because planned maintenance activities are predictable, and excess emissions can be avoided by scheduling maintenance during shutdown periods. Further, EPA contended that the provision was potentially broadly applicable because it contained a “defect” that could be interpreted as not requiring a source to establish all elements of the affirmative defense.
The court started its analysis by noting that the CAA was silent if a state may include in its SIP the availability of an affirmative defense against such penalties. Consequently, the court said that EPA may not interfere with a state’s broad authority to determine the methods and particular control strategies to use to achieve the statutory requirements including its decision to include the availability of an affirmative defense for certain unplanned SSM events under narrowly defined circumstances so long as the SIP revision is consistent with the CAA requirements.
The found that EPA’s reasoning for its partial approval of the SIP revision was consistent with its past policy guidance as well as was the result of a formal and deliberative decision-making process. Therefore, the court held that the agency’s action was entitled to Chevron deference.
The court then found EPA’s approval of the affirmative defense for unplanned SSMs was a permissible construction of the statute. The court also found that the text of the SIP supported EPA’s view that a source owner or operator may not be required to establish all elements of the affirmative defense. The court found EPA’s reasoning met minimal standards of rationality and therefore ruled the agency had not acted was not arbitrary, capricious, or contrary to law, when it disapproved the portion of the SIP revision containing an affirmative defense for planned SSM activity.
Saturday, March 31st, 2012
The Clean Air Act imposes an alphabet soup of emission control technologies on owners and operators of stationary sources. Depending on the regulatory program and air pollutants, a facility may have to comply with BACT, BART, BDT, GACT, LAER, MACT and RACT.
While the process of identifying the applicable emission standard is largely a technical exercise, the decision in U.S. v Minnkota Power Cooperative, Inc. and Square Butte Electric , 2011 U.S. Dist. LEXIS 148801(D.N.D. 12/21/11) illustrates the legal issues associated with the selection of air emission control technologies for a particular facility or emission source.
In this case, EPA issued a notice of violation to the Milton R. Young Station owned by Minnkota Power asserting that the company had undertaken major modifications without first undergoing New Source Review (NSR) for Prevention of Significant Deterioration (PSD). Unlike other CAA regulatory programs that impose nationwide emission limitations on particular categories of air pollution, the NSR program is a facility-specific review. NSR/PSD is triggered when an existing source proposes to undertakes a physical change or a change in its method of operation that will result in a significant emissions increase. The facility must obtain a pre-construction permit and be equipped with the “best available control technology” (BACT).
After more than six years of analysis and negotiations, EPA, North Dakota, and Minnkota Power entered into a consent order elected to settle the EPA’s dispute through the Consent Decree where the company agreed to install BACT. In other consent decrees that EPA had entered into as part of its coal power plant NSR enforcement initiative, selective catalytic reduction technology (“SCR”) was selected as BACT for Nitrogen Oxide (NOx) emissions. However, the Minnkota Power plant burned North Dakota lignite whose particular properties posed technical challenges. As a result, the parties agreed that North Dakota would make a NOx BACT determination using applicable EPA guidance. The consent order provided that North Dakota’s BACT Determination would be binding unless the EPA demonstrates that it is not supported by the state administrative record and not reasonable in light of applicable statutory and regulatory provisions
After a four-year effort, the North Dakota Department of Health concluded that SCR was technical infeasible and identified non-selective catalytic reduction (“SNCR”) plus advanced separated overfire air (“ASOFA”) as BACT for the plant. EPA challenged this decision.
The court found that North Dakota had followed the five-step methodology set forth in EPA’s “New Source Review Workshop Manual”(NSR Manual). Step One requires the permitting authority lists all “potentially available” control options.
In Step Two, the permitting authority eliminates “technically infeasible” control options from this list. A control option is “technically feasible” if it has been “demonstrated” or if it is both “available” and “applicable.” A control option is “demonstrated” if it “has been installed and operated successfully on the type of source under review.” A control option is “available” if it “can be obtained by the applicant through commercial channels or is otherwise commercially available. A control option is ‘applicable’ if it can reasonably be installed and operated on the source type under consideration.”
In Step Three, the remaining control options are ranked and then listed in order of control effectiveness.
Under Step Four, the energy, environmental, and economic impacts of the control options are evaluated to support the validity of the top-ranked control option or provide clear evidence why the top-ranked control option does not quality as BACT.
Finally, the most effective, technically feasible control option not eliminated in Step Four is selected as BACT, and the permitting authority sets an emission limitation that is appropriate for the particular control option
After performing this analysis, North Dakota Department of Health made the following findings and conclusions
- SCR had not been installed at a facility that usedNorth Dakota lignite
- The lignite coal contained high quantities of soluble sodium and potassium that interfered with the catalyst.
- The properties of the ash produced from burning North Dakota lignite is the most complex and severe of any coals in the world, and interferes with catalysts used for NOx reduction.
- A catalyst vendor stated it was unaware of any SCR being used with the level and form of sodium in the ash at the Milton R. Young Station.
- A vendor also said the impact of the on the back end of the SCR process was were not well understood, presented significant design risk and would require more investigation to predict its performance to make it a commercially available technology.
- Vendors said they would not provide a guarantee for the catalyst life without at least a one-year pilot scale testing and indicated they were not aware of any SCR being installed in theUnited Stateswithout a catalyst life guarantee.
North Dakota concluded Minnkota Power was not required under BACT to assume the risk associated with the failure of a technology that has never been used on a North Dakotafired unit or a source with similar flue gas characteristic. As a result, the State concluded that selective non-catalytic reduction (“SNCR”) technology was BACT because of the unique characteristics of North Dakota lignite, the cyclone-fired boilers, and their combined adverse interactions with the SCR catalyst
EPA argued that that because SCR technology has been widely deployed at coal-fired power plants across the country,North Dakotashould have selected SCR as the best available control technology (“BACT”). However, the court said the record showed that North Dakota carefully considered the impacts of fuel and boiler types on SCR operability. The Court found that there was no evidence that North Dakota’s decision was arbitrary.
Saturday, March 31st, 2012
A federal district court ruled that purchaser of a coal-fired power plant was held liable as a successor for violations of the New Source Review program that had occurred prior to the transaction. The court said the purchaser had expressly assumed the liabilities even though the order of the bankruptcy court approving the sale provided that the purchaser was not to be considered a successor of the seller of the plant.
In United States v. La. Generating, LLC, 2011 U.S. Dist. LEXIS 137973 (M.D. La. 12/1/11), the Cajun Electric Power Cooperative (Cajun Electric) began constructing the “Big Cajun II” (BCII) coal-fired power plant in 1976 amendments to the Clean Air Act (CAA). Big Cajun began operating in 1981. In 1994, Cajun Electric filed a chapter 11 bankruptcy proceeding and a bankruptcy trusts was appointed in 1995.
Meanwhile, in 1994 and 1995, Cajun Electric upgraded the turbines of Units 1 and 2 (“the 1994/95 work”). Cajun Electric did not obtain a Preventing of Significant Deterioration (PSD) permit prior to starting work. In 1998 and 1999, Cajun Electric replaced portions of the primary boiler reheaters (“the 1998/99 work”) also without obtaining a PSD permit. The cost of each project was estimated at $5 million.
As part of the Cajun Electric bankruptcy reorganization plan, the trustee solicited bids for substantially all of Cajun Electric’s assets, including BCII. After a protracted auction process, a subsidiary of NRG Energy, Louisiana Generating, LLC (LaGen), submitted a final bid that was accepted by the trustee and memorialized in what was called the Fifth Amended Asset Purchase Agreement (APA).
The APA provided, inter alia, that the bankruptcy court confirmation order would state that LaGen would not assume or be liable for any liabilities of Cajun Electric except for “Assumed Liabilities and any Environmental Liabilities that attach to the owner of any of the Acquired Assets by operation of law.” The definition of “Environmental Liabilities” included any known or reasonably expected liability or obligation….. under any Environmental Law.” [emphasis added]. The APA also contained representations that the company was in material compliance with all environmental laws permits, had obtained all permits necessary to operate the business and that no other permits were required for the business.
In October 1999, the bankruptcy court issue an order approving the sale “free and clear” under section 363 of the Bankruptcy Code. “free and clear”. The confirmation order also provided that LaGen was not a successor and “shall not have any liability for any claims against [Cajun Electric] as a result of s purchase of the Acquired Assets”. LaGen acquired BCII in April 2000.
In September of 2001, LaGen submitted a revised Title V permit application for BCII. While the application was still pending, EPA issued a notice of violation (“NOV”) regarding the 1998/99 work. Despite the NOV, the state issued the Title V permit and renewed this permit in 2011. The EPA did not formally object to the issuance of the permit or its renewal.
In 2009, the federal government filed a lawsuit against LaGen seeking civil penalties and injunctive relief for violations of the CAA New Source Review (NSR) permit program for Prevention of Significant Deterioration (PSD) and the Title V permit. Under the NSR/PSD, a new major source or an existing major source that is to undergo a physical change or change in operation (modification) that will result in a significant net increase in pollutants must apply for a pre-construction permit and install pollution control technology known as Best Available Control Technology (BACT). Work that qualifies as “routine maintenance, repair and replacement” is exempt from the NSR program.
The parties each filed motions for summary judgment. LaGen argued that the CAA only imposed liability on the person owning or operating the facility when the violation occurs and prohibited the application of successor liability. Specifically, LaGen argued that the express language of section 165 of the CAA and the implementing regulations of 40 CFR 52.21 imposed the obligation to obtain a PSD permit on the owner or operator who actually engaged in the construction or modification project that triggers the requirements. Likewise, LaGen said the State Implementation Plan (SIP) only prohibited construction without a permit. In other words, LaGen argued PSD was a pre-construction program and there was nothing in the statutory or regulatory language extended PSD obligations to cover operation by entities, including a purchaser who acquired a plant after construction is completed from operating the source without a PSD permit. [emphasis added].
LaGen also pointed to a line of cases holding that violations of the PSD pre-construction permitting requirements occur at the time of construction and do not extend to post-construction operations. LaGen also claimed that a substantial majority of district courts have held that PSD imposes a one-time permitting obligation and that these cases have rejected any argument based on a “continuing violation” theory. Since the alleged modifications occurred prior to LaGen’s acquisition of the Units 1 and 2, LaGen said it could not have complied with or violated the obligation to comply with PSD prior to the commencement of the projects. Moreover, since PSD liability could not attach to the owner of acquired assets by operation of law, LaGen asserted that it could not assumed liabilities for the 1998/99 work under the APA.
The court rejected the notion that successor liability was precluded under the CAA, saying the doctrine was so well established that Congress would have to expressly exclude its application in a statute. Then ignoring the express language of the order issued by the bankruptcy court, the court proceeded with a successor liability analysis. Pointing to the language of APA section 2.4 that the purchasers assumed “any Environmental Liabilities that attach to the owner of any of the Acquired Assets by operation of Law”, the court concluded that LaGen assumed any environmental liability that it knew about or reasonably expected at the time of the signing of the Fifth APA.
The court said the 1998/99 work was the type of liability that LaGen could have assumed under APA Section 2.4. The court noted that when NRG first considered purchasing the BCII assets in 1996, a member of NRG’s due diligence team was concerned about the 1994/95 work and that the trustee had notified all of the bidders about the 1998/99 work but NRG did not perform any due diligence regarding potential PSD applicability. The government argued that this was evidence that NRG effectively hid its head in the sand while the defendant said it relied on the trustee’s representations that the plant was in compliance with environmental laws. As a result, the court said there was a genuine dispute if the Defendant knew or reasonably expected the 1998/99 work to BCII Units 1 and 2 created liability under the CAA that precluded granting of summary judgment
The defendant also argued that the government’s PSD claim was barred by the statute of limitation. LaGen said the five-year SOL began to run in 1998 when construction on the units began and had expired in 2003-six years before the government brought its action. The government, on the other hand, asserted that the SOL was tolled because the PSD violation was ongoing. The court agreed that since the CAA did not have a period of limitation period for enforcement actions, the general five-year statute of limitations found in 28 U.S.C. § 462 applied. However, the court ruled that while the applicable caselaw suggested that the SOL had not expired, the government was only able to seek penalties for the five years preceding the time the suit was filed.
The government also asserted that LaGen had submitted a deficient Title V permit by not identifying the applicability of the PSD program. Under EPA’s “no look back” policy, LaGen argued it had no obligation to evaluate prior projects when completing its Title V permit. The court ruled that even if an application had no “look back” obligation, it has an ongoing duty to supplement or correct applications “upon becoming aware of such failure or incorrect submittal.
LaGen said its certification obligation could be based only on a reasonable belief at the time of the submission. The court disagreed, saying that an applicant to perform a reasonable inquiry. Moreover, since LaGen had not properly supplemented its Title V permit to reflect the PSD and BACT applicability, the court declined to find that EPA’s failure to object to the permit renewal precluded the enforcement action. To hold otherwise, the court said, would be to encourage and reward sources for not being forthright in their Title V permit applications.
Wednesday, March 28th, 2012
Historical environmental compliance is critically important in corporate transactions especially when a business or facility may be subject to a regulatory programs that is evolving or subject to re-interpretation such as the New Source Review program. In such cases, the parties will try to contractually allocate the risks. Despite the fact that these agreements are heavily negotiated, regulatory issues may subsequently arise that the parties may have no contemplated or that the parties simply disagree on how the agreement addressed the issue.
An interesting example is the unreported decision in Lucite International, Inc. v E. I. Du Pont De Nemours and Co., No. 2:09-cv-02279 (W.D. Tenn. 5/17/11) involved a 1993 sale of aMemphis acrylics plant by DuPont to ICI Acrylics, Inc. (now known as Lucite International, Inc). Unreported decision tend to be overlooked by the legal trade press because they have no precedential value. However, the vast bulk of law is made in unreported cases and these opinions can provide insights on how judges may view similar situations or provide roadmaps on what arguments may present the best chance of success. These informal decisions can also often provide practical insights and lessons learned about contract drafting and interpretation.
In this case, theMemphisplant manufactured methyl methacrylate. The manufacturing process used a sulfuric acid recovery unit (“SAR Unit”) to convert spent acid sludge into sulfuric acid. In 1973, the Tennessee Division of Air Pollution Control (the “TDAPC”) classified the SAR Unit as a “process” instead of a “sulfuric acid plant. If the SAR unit had been classified as a sulfuric acid plant, it would have been potentially subject to the New Source Performance Standards (NSPS) of the Clean Air Act (CAA). The TDAPC subsequently delegated permitting authority to theMemphisand Shelby County Health Department (“MSCHD”). This agency initially informed Dupont that the SAR was considered to be a ‘pollution prevention device’ and not a NSPS-regulated unit because it recycled the spent acid to the process eliminating the discharge of spent acid to the process server.
In 1975, Dupont applied for a permit from the MSCHD to construct a second furnace train. In 1982, the MSCHD issued a permit that allowed the plant to emit 11.9 tons per day of sulfur dioxide (SO2) which exceeded of the amount permissible under the NSPS. EPA subsequently approved the facility’s Title V operating permit with the SO2 emission rate.
In November 1985, the MSCHD advised Dupont that it had re-classified the SAR Unit as a sulfuric acid plant. However, the MSCHD informed Dupont that it would not enforce the NSPS or retroactively penalize Dupont for modifications made between 1975 and 1978 since the facility had relied in good faith on the prior determination that the SAR unit was not subject to NSPS. However, the agency cautioned that any future modification would trigger the NSPS. The MSCHD indicated in its letter that while it believed the SAR classification was correct, DuPont could request a determination by the EPA.
In December 2002, the EPA conducted a multimedia compliance investigation and subsequently concluded that the plant was operating in violation of the NSPS emission limits for SAR units since at least 1978, when the second furnace train came online. Following two years of negotiations, EPA and Lucite entered into a consent decree in February 2006 where Lucite agreed to install dual absorption technology to bring the SAR unit air emissions within NSPS and paid almost $25 million in civil penalties. The consent decree was terminated in 2008 after the court determined that Lucite had complied with its terms.
In May 2009, Lucite filed a breach of contract action against Dupont for failing to honor it’s indemnification obligations under the 1993 the Asset Purchase Agreement (APA). Specifically, Lucite alleged that Dupont had breached APA Clause 12.2.1 that provided that the seller indemnify the buyer for “Environmental Liabilities” attributable to conditions existing at the Closing Date.
Dupont argued that it was not required to indemnify Lucite because the environmental liabilities resulted from Lucite’s failure to install dual absorption technology. Dupont claimed that Lucite had failed to mitigate or avoid exacerbating environmental liabilities. Dupont specifically pointed to APA clause 12.2.2 providing that its indemnity obligation did not extend to environmental liabilities that “have arisen, been increased, exacerbated, enhanced, or caused as a result of an act or omission (whether direct or indirect) of the buyer . . .”. Dupont also argued that it was not required to indemnify Lucite the NSPS determination by EPA was a change in legislation after the closing of the APA agreement.
On Dupont’s claim that Lucite caused its damages by failing to install the dual absorption technology, the court said that for an act or omission to constitute a complete bar to indemnity, the court said that Dupont would have to show that Lucite was the sole cause of the environmental liabilities but had failed to do so since the EPA Investigation Report had concluded that the SAR had been exceeding the NSPS emission limits years before Lucite purchased the site.
On the related issue that Lucite failure to mitigate its damages relieved Dupont of its indemnity obligation, the court said the duty to mitigate only attaches once a material breach of contract occurs and then all that is required of the non-breaching party is to act reasonably so as to not unduly enhance the damages. The court said the APA did not alter the traditional mitigation duty. The court pointed to APA Clause 12.4.1 which suggested a narrow range of activities that Lucite had to perform to mitigate against environmental liabilities, such as “carrying out (where reasonably practicable) soil tests” (APA Clause 184.108.40.206) and “settling a claim of any party . ..with respect to loss, harm or other damage” (APA Clause 220.127.116.11).
Under these clauses, the court continued, Lucite only had to take reasonable and practical steps to mitigate damages. Requiring Plaintiff to install a multi-million dual absorption technology prior to an allegation or determination by a government regulator that the NSPS apply to the SAR Unit would not be reasonable or practicable. Thus, the court found that the earliest point at which a “potential environmental liability” may have arisen to trigger APA Clause 12.4.1 was when the EPA first informed Lucite that it intended to assert claims for violations of the NSPS. Prior to this event, the court reasoned, Lucite was not aware of any “potential environmental liabilities” and thus could not be found to have failed to mitigate such liabilities under APA Clause 12.4.1. The court also rejected Dupont’s interpretation that Lucite had a duty to “monitor the status of the law” and to “proactively request” an NSPS applicability determination from the EPA.
In response to the Lucite’s claim that Dupont had breached its environmental compliance warranty, Dupont asserted that its disclosures in the Schedules of the APA relieved it of any duty to indemnify. Dupont specifically pointed to APA Clause 9.7 providing that “[t]he Buyer shall not be entitled to make any claim with respect to any breach or alleged breach of the Warranties to the extent that: the facts, matters or circumstances giving rise thereto (with respect to which any such claim or alleged claim arises) have been disclosed in this Agreement or the Schedules hereto.” Dupont also relied on APA Clause 1.2.2 that stated that the schedules forms part of the APA and Clause 9.2.1 that provided that the warranties are given subject to the information disclosed in the Schedules. Dupont pointed out that ICI had requested information identifying all environmental capital expenditures during the last ten years that were greater than $100,000 and that the schedules referred to a Site Assessment Report and Environmental Baseline Study that included an entry of “SO2 Stack Dual Absorption” at a cost of “8 million dollars. Dupont also cited a document disclosed in the schedules titled “Environmental Topics and Path Forward,” that summarized a meeting between ICI and MSCHD representatives concerning emissions permits in October 1992
However, the court ruled that the disclosures in the APA Schedules did not viscitate its indemnity obligation. The court said the disclosure about the SO2 Stack Dual Absorption reflected a potential but unauthorized capital project that did not come to fruition. The mere fact that Lucite subsequently had such a project on its capital forecast, the court said, did not obligate Lucite to install the equipment. The court also found that pre-closing communications did not relieve Dupont of its potential indemnification obligation since the APA constituted the final, integrated agreement among the parties.
The court said that Dupont agreed to indemnify Lucite for environmental liabilities attributable to pre-closing conditions and failed to cited any cases supporting its arguments that pre-closing disclosures can nullify express representations in a contract. The court pointed out that Delaware law provided that a party to a contract can rely on express warranties and representations in that contract regardless what they learned or should have learned during due diligence. The court said contracting parties do not have to prove that they were justified in relying on the representations and warranties set forth in the contract. Accordingly, the court held that Lucite’s failure to install dual absorption technology prior to being informed by the EPA that the agency intended to assert claims against Plaintiff for violations of the NSPS did not constitute an omission or a failure to mitigate under APA Clause 12.4.1. However, the court did find there was an issue of material fact as to when the EPA informed Plaintiff of its intent to bring these claims.
Dupont also argued that EPA’s determination that the NSPS applied to the SAR Unit fell within the change of law exclusion to its indemnity obligation since the EPA interpretation ran counter to prior rulings of the state and MSCDH. The court rejected this claim, holding no change in legislation occurred when the EPA issued its 2003 Investigation Report. The court said neither the governing law enforced by the EPA or the NSPS regulations had changed since the 1993 closing date. The court said that the MSCDH had informed Dupont in 1985 that the SAR Unit was incorrectly classified as a sulfuric acid process but had decided to exercise its discretion not to enforce the NSPS. The fact that EPA decided to enforce the long-existing NSPS regulations did not constitute legislation not in effect at closing.
Moreover, the court rejected the assertion that the MSCDH had “grandfathered” and exempted the SAR from the NSPS regulation. The court said EPA’s delegation to the state expressly reserved EPA’s right to enforce any applicable standard and EPA was not bound by any decision of the state or local authority. In addition, the court said, neither Congress nor the EPA delegated to local authorities the power to make local plants “exempt” from federal laws and regulations. Indeed, the court noted that MSCHD acknowledge in its letter to Dupont that the EPA could make a subsequent enforcement determination and informed Dupont that it could request a determination by the EPA if they so desired. Regardless of what the parties believed, the court ruled, EPA retained the authority to decide that the parties’ understanding of the compliance status of the SAR Unit was in error, regardless of whether it was operating under emissions permits issued by the MSCHD.
The court docket had lots of sealed documents presumably to prevent disclosure of confidential information or trade secrets. Recently, the parties reacged a confidential settlement of this case.
Monday, March 12th, 2012
In US v Ameren Missouri, 2011 U.S. Dist. LEXIS 152426 (E.D.Mo. 1/27/12), the federal government alleged that the defendant had violated the Clean Air Act and the State Implementation Plan (SIP) when it performed major modifications for a coal-fired power plant without first undergoing new source review (NSR) for prevention of significant deterioriation (PSD).
EPA asserted that the modifications enabled units 1 and 2 at the Rush Island Plant to burn more coal per hour of operation, allowed the Units to operate for longer periods of time and release more SO2. EPA alleged that the plant should have obtained a PSD permit , did not undergo BACT analysis for SO2, did not install or operate BACT controls for SO2, failed to comply with BACT emissions limits for SO2 and operated the units after undergoing unpermitted major modifications.
The parties agreed that the five-year statute of limitations (SOL) set forth in 28 U.S.C. 2462 was applicable to the civil penalties sought by EPA for the 2001 and 2003 modification projects. EPA filed its action in 2011 but argued that the SOL did not apply because the violations were ongoing.
The Missouri SIP and the facility Title V permit prohibited the commencement of a major modification or beginning operation after a major modification. The court said the plain meaning of this language was that it was a violation to begin construction and operation without a permit but did not prohibit ongoing operation without a permit. Since the 2001 and 2003 alleged violations occurred more than five years before the complaint had been filed, the court dismissed EPA’s civil penalty claims for failure to comply with the PSD and SIP requirements as well as the Title V PSD requirements. For the same reasons, the court dismissed the claim for failing to obtain a BACT determination and operating without complying with BACT.