With the nation is in the middle of building pipeline infrastructure to transport natural gas from fracking operations as well as Canadian oil, I suspect we will see more case like Enbridge Pipelines (Ill.) L.L.C. v. Moore, 633 F.3d 602 (7^th Cir. 2011) where landowners argued that a 1939 pipeline easement had expired. Presumably, the landowners wanted to negotiate a richer deal for new easements.

In this case, the plaintiff was trying to build a 170-mile-long pipeline in Illinois as part of a larger project of pipeline construction to meet increased demand for Canadian oil. A 120-mile segment of the proposed construction route already contained a 10-inch pipeline originally constructed in 1939 and that had not been in use for many years. Enbridge wanted to replace the 10-inch pipeline with a 36-inch one.

The pipeline route had been created by easements from private property that had been granted to predecessors of Enbridge. The easement conveyed the to the original grantee “the right to lay, operate, and maintain a pipe line for the transportation of oil, gasoline and/or other fluids.” The easement also applied to the grantee’s successors and assigns “so long as such pipe lines or other structures are maintained.” The holder of the easement was also required to compensate landowners for any and all damages to crops, fences, and land resulting from the construction, operation or maintenance of the pipe lines.

The pipeline had been inactive since 1988 when Enbridge acquired the rights to the easement. After learning of the proposed pipeline upgrade, the owners whose land was subject to the easement contended that Enbridge had forfeited the easements by failing to maintain the pipeline in good working condition. The owners said that Enbridge had failed to maintain cathodic protection, valves and pumps and seams. They alleged that segments of the pipeline were missing, and that joint or seam failures had not been repaired. The plaintiffs also alleged that the interior of the pipeline had not been cleaned.

The court said that the legal meaning of abandonment was a deliberate act and did not encompass poor maintenance. While the court acknowledged that the original pipeline had not been in use for many years, the court said there was no evidence that the defendant intended to abandon the easement. Using an economic analysis (the court is after all located in Chicago), the court said the easement owner had foreseen the possibility that demand for transportation of oil by pipeline would someday justify placing the pipeline (or a replacement) into service but there was no economic justification for keeping the pipeline in “mint” operating condition until that time.

The court also found that the word “maintain” was ambiguous but did not require that the pipeline be maintained in mint condition. A rule that forfeited a person’s property right because they failed to maintain the property in good condition would cast a cloud of debilitating uncertainty over property rights, the court concluded. To hold that failure to maintain the pipeline would cause the easement to be extinguished, the court said, would engender wasteful maintenance. The court said such a requirement would also induce expenditures on maintenance intended not to enable the productive use of the property but merely to avoid forfeiture of the property right.

The court also said that a reasonable reading of the word “pipeline” in the easement was that the word did not refer to the pipe itself but to the pipeline in the sense of a route for transporting oil, just as one might speak of an “air corridor” between New York and Chicago even if no airlines were operating between those cities. The court said that maintaining the pipeline would then just mean preserving the option to use the easements for future transportation of oil, even if the existing pipeline crumbled to dust.

The defendant landowners argued that because the instrument creating the easement referred to “such pipe lines or other structures”, the phrase applied to the physical pipeline, not the easements. As a result, the dismantlement of the pipe would have terminated the easements. However, the court said even this reading would not defeat Enbridge’s claim. The court said that all that was required of the successive easement holders was to engage in minimal maintenance to put have the pipeline put back into service with additional expenditures to clear out the rust and replace broken parts.

Contrary to the landowners’ claims, the court ruled that Enbridge had engaged in considerable maintenance in 1992, 1993, and 2004. The court said there was no evidence of any missing segments, and that an Enbridge engineer who performed 27 “integrity digs” testified that the pipeline was capable of transporting liquid. His affidavit described the pipeline as being close to being as good as new and could with relative ease be placed back into active service as a crude oil line, a gas line, or a water line.  The court said this was sufficient to show that the owners maintained the pipeline within any meaning that could reasonably be assigned to the easements and had no intention of abandoning it, for if they had intended to do so they wouldn’t have spent even a penny on maintenance.

Hager’s of Cohasset, Inc. v. Nelson, 2011Minn. App. Unpub. LEXIS 156 (Minn.Ct. App. Feb. 15, 2011) is yet another lesson from a long line of cases that illustrate the risks of not using counsel for commercial property transactions especially those have problematic environmental issues.

In this case, the plaintiff operated a fuel-oil business. In October 2007, plaintiff decided to sell his property and divided it into two parcels. After selling Tract A, he entered into a purchase agreement with the defendant for Tract B. Another defendant, the broker, served as a dual agent.

The broker drafted a clause at the instruction of the defendant buyer that provided the sale was contingent on seller obtaining a letter from the Minnesota Pollution Control Agency (MPCA) stating that the land was free from any future clean up. In addition, the clause stated that “Seller was to have tanks removed and proper fill removed and new fill in place prior to closing per MPCA rules in place at present time, seller to provide buyer with a completion certificate by the MPCA. Buyer to have no financial obligation for the removal and compliance with MPCA rules and regulations”

After the contract was signed, the plaintiff removed the above-ground fuel tanks and fuel pumps removed from tract B but did not provide buyer with any documentation from MPCA that the tanks were removed in compliance with MPCA rules and regulations, nor a letter from the MPCA stating that the land was free from future cleanup. The only letter from the MPCA seller provided was dated six months before the parties had entered into the purchase agreement that addressed a petroleum release associated with two 10,000-gallon USTs that had been removed in 2007. The MPCA closure letter simply indicated the petroleum release had been adequately addressed and did not require any additional investigation or cleanup work at that time. However, the letter also said that “file closure does not mean that all of the petroleum contamination has been removed from this site” and “that the MPCA reserves the right to reopen this file.” In addition, the letter stated “This letter does not release any party from liability for the petroleum contamination . . . . If future development of this property or the surrounding area is planned, it should be assumed that petroleum contamination may be present.”

Buyer refused to close, saying that the 2007 MPCA letter was not satisfactory. Seller then filed a breach of contract action and sough an order compelling specific performance. Seller also sued the broker, asserting that the broker breached his fiduciary duty because he drafted the purchase agreement per Nelson’s instructions without seeking legal advice or additional expertise from the MCPA about the conditions.

The buyer and broker moved for summary judgment and dismissal of all of Hager’s claims. The district court granted summary judgment in favor of buyer and the broker, concluding that the 2007 MPCA letter did not satisfy the minimum requirements of the condition because it predated the purchase agreement, released no party from liability, and indicated that it should be assumed that petroleum contamination may be present.

The appeals court affirmed, holding that because seller did not provide buyer with any documentation from the MPCA related to the tank removal in May 2008, the conditions precedent were not satisfied.  On the claim against the broker, the court said seller had not shown that the broker had a duty to obtain legal advice or consult with MPCA prior to drafting the condition precedent.

Approximately 2.5 million miles of pipelines transverse the United States carrying hazardous liquids and natural gas from producing wells to end users (residences and businesses). Many of these pipeline networks are aging while others such as natural gas gathering pipelines remain largerly unregulated. Moreover, development has encroached on many of pipelines that were formerly located in rural areas, thereby increasing the risks posed by these pipelines.

Pipeline safety has been drawing increasing scrutiny from Congress. The “Pipeline Safety Improvement Act of 2002” required PHMSA to develop its risk-based integrity management program for transmission pipelines. Under the “Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006,”  PHMSA also establish minimum standards for integrity management for distribution pipeline networks. Under the rules developed by PHMSA, all distribution pipelines are considered to be in high-consequence areas because they are largely located in populated areas. As a result, distribution integrity management requirements apply to all distribution pipelines. However, the distribution pipeline rules tend to be less prescriptive than those for transmission lines due to the lower operating pressures.  Congress recently mandated that DOT review the sufficiency of existing federal and state laws and regulations to ensure the safety of hazardous liquid and gas gathering pipelines under the “Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.”

Despite the pervasiveness of pipelines, these structures are often not flagged or discussed in due diligence. A recent report by the GAO (“Collecting Data and Sharing Information on Federally Unregulated Gathering Pipelines Could Help Enhance Safety”; http://www.gao.gov/products/GAO-12-388) discusses the need for additional information about the pipelines used to collect natural gas from fracking operations.

The GAO indicated there are three main types of pipelines: Gathering, Transmission, and Distribution Pipelines

• Gathering pipelines- Gas gathering pipelines collect natural gas from production areas, while hazardous liquid gathering pipelines collect oil and other petroleum products. These pipelines then typically transport the products to processing facilities, which in turn refine and send the products to transmission pipelines. According to PHMSA gathering pipelines range in diameter from about 2 to 12 inches and operate at pressures that range from about 5 to 800 pounds per square inch (psi). These pipelines tend to be located in rural areas but can also be located in urban areas. PHMSA estimates there are 200,000 miles of gas gathering pipelines and 30,000 to 40,000 miles of hazardous liquid gathering pipelines. PHMSA does not regulate most gathering pipelines in theUnited States. For example, PHMSA regulates roughly 20,000 miles out of the more than 200,000 estimated miles of natural gas gathering pipelines. Similarly, PHMSA regulates only about 4,000 miles of the 30,000 to 40,000 estimated miles of hazardous liquid gathering pipelines.

• Transmission pipelines- PHMSA has estimated there are more than 400,000 miles of gas and hazardous liquid transmission pipelines. These pipelines can carry product over hundreds of miles, to communities and large-volume users (e.g., factories). Compressor stations maintain product pressure in natural gas pipelines while pumping stations maintain product flow for hazardous liquid transmission pipelines. Transmission pipelines tend to have the largest diameters and pressures of any type of pipeline, generally ranging from 12 inches to 42 inches in diameter and operating at pressures ranging from 400 to 1440 psi.

• Distribution pipelines- PHMSA has estimated there are roughly 2 million miles of distribution pipelines which transport natural gas from the transmission pipelines to residential, commercial, and industrial customers. These pipelines tend to be smaller, sometimes less than 1 inch in diameter, and operate at lower pressures—0.25 to 100 psi.

The Department of Transportation’s (DOT) Pipeline and Hazardous Materials Safety Administration (PHMSA) has established uniform, minimum safety standards that establish specifications for the design, construction, testing, inspection, operation, and maintenance of pipelines. The PHMSA regulatory program uses a four-tier classification system based on their proximity to populated and environmentally sensitive areas. Class 1 involves offshore areas. Class 2 includes locations with 10-45 buildings intended for human occupancy that are within 220 yards of the center line of the pipeline. A class 3 location is an area with more than 46 buildings intended for human occupancy that are within 220 yards of a pipeline or an area where the pipeline lies within 100 yards of either a building or a outside area such as a playground that is occupied by 20 or more persons at least 5 days a week for 10 weeks in any 12-month period. Class 4 locations where unit buildings with four or more stories above ground are prevalent

In addition, PHMSA has developed supplemental risk-based regulatory program termed “integrity management” for hazardous liquid and natural gas transmission pipelines and natural gas distribution pipelines in “high-consequence areas” where an incident would have greater consequences for public safety or the environment. Pipeline operators are required to systematically identify and mitigate risks to pipeline segments located in high-consequence areas, which are defined differently for the three types of pipelines.

For hazardous liquid pipelines, high-consequence areas include areas of highly populated areas, other populated areas, navigable waterways, and areas unusually sensitive to environmental damage. For natural gas transmission pipelines, high-consequence areas include highly populated or frequently used areas, such as parks. Most natural gas distribution pipelines would generally be considered to be in high-consequence areas since they are typically located in highly populated areas. High-consequence areas can be in Class 1, 2, 3, or 4 locations.

States may be authorized to conduct inspections for interstate pipelines, as well as inspections and associated enforcement for intrastate pipelines. State pipeline safety offices are allowed to issue regulations supplementing or extending federal regulations, but these state regulations must be at least as stringent as the minimum federal regulations. If a state wants to issue regulations that apply to pipelines that PHMSA does not regulate, such as unregulated gathering pipelines, it must do so under its own (state) authority. According to GAO, only 3 of the 39 state agencies interviewed reported that they collect and analyze comprehensive pipeline spill and release data on federally unregulated pipelines.

According to GAO, leading causes for leaks and spills from transmission lines is corrosion while excavation is the most common cause of damage to distribution lines. Because of their relative low pressure, damaged distribution lines tend to develop slow leaks instead of explosions. However, undetected gas from slow leaks can migrate long distance along utilities and sewer lines and accumulate in homes where inadvertent ignition could lead to fire or explosion.

GAO said states identified the following risk factors for pipelines:

• Construction quality- GAO said that state agencies reported the construction is critical to ensure the long-term integrity of the pipeline because the installation methods and materials used in pipeline construction affect the pipeline’s resistance to deterioration over time. For example, regulated pipelines may not be installed unless they have been visually inspected at the site of installation.

• Maintenance practices-State agencies said periodic maintenance including inspecting and testing equipment is important to prevent leaks and ruptures. Unfortunately, there are no such federal requirements unregulated gathering pipelines.

• Location-State and local safety agencies may not know or may be uncertain about the locations and mileage of unregulated pipeline infrastructure. This information is particularly useful for “Call Before You Dig” programs operated by states and localities. If unregulated gathering pipelines are unmarked and program officials do not know the location of the pipelines, businesses and citizens may damage a pipeline during excavation, which could result in fatalities, injuries, or damage to property or the environment as well as the shutting down of the pipeline for repair.

• Pipeline integrity- As previously mentioned, the leading risks to pipeline integrity is excavation damage and corrosion. Although states reported that excavation damage to a pipeline from nearby digging activities was the leading cause of pipeline incidents, many state agencies told GAO they often did not know or had limited knowledge about the integrity of unregulated gathering pipelines, thus increasing the potential for such damage. GAO reported that corrosion was reported as the cause of about 60% of regulated gas gathering pipeline incidents from 2004 to 2010. However, there is limited information on the integrity of unregulated gathering pipelines to assess the internal and external condition of these pipelines.

• Land Use Changes-State pipeline safety agencies also told GAO that increased urbanization that results in encroachment on existing pipeline rights-of- way is a moderate or high risk factor. For example, GAO reported stated that although a new housing or business development can change a location’s designation from Class 1 to a higher class that would then fall under PHMSA’s jurisdiction, the operator may not be aware of the development and therefore would not monitor and apply more stringent regulations along that pipeline.

• Increased extraction of oil and gas from shale deposits- GAO said this activity accounted for 16% of the total domestic natural gas supply in 2009 and is projected to increase to approximately 47% by 2035. As a result, state and federal safety officials have identified new gathering pipelines related to shale development as a potential public safety risk since these pipelines tend to have larger diameters and operate at higher pressures that traditional transmission pipelines. Such information can be used to help reduce future incidents.

In Shelton Property Rural Acreage, LLC v Placid Oil Co., 2011 U.S. App. LEXIS 16681 (5^th Cir. 8/10/11), Placid Oil operated oil wells on leased property from 1942 to 1956. In 1986, Placid filed a chapter 11 bankruptcy proceeding. The bankruptcy court issued a confirmation order in 1988 that contained a discharge of all claims except those created or assumed by the reorganization plan. The order also included a discharge for any future claims for damages that occurred prior to the discharge.

In 2002, Shelton Property Rural Acreage, LLC (Shelton) purchased the property that had been leased by Placid. After discovering contamination associated with the prior drilling operations,Shelton commenced a lawsuit against Placid in state court. Placid filed an adversary proceeding with the bankruptcy court, arguing that since the property owner at the time of the bankruptcy proceedings had not filed a proof of claim for any alleged environmental damage to the property, Shelton’s claim had been discharged by the bankruptcy court’s 1988 order.

In response,Shelton argued the discharge should not apply to its claim because the prior landowner had not receive adequate notice of Placid’s bankruptcy proceeding. Shelton asserted that the prior owner should have been considered a known creditor because a water study published in 1958 had showed that water wells on the property were contaminated due to oil and gas activities. Moreover,Shelton said an article in a June 1964 issue of Oil and Gas Journal discussed that the Little River bordering Shelton’s property was being polluted due to unlined oil and gas pits.

The bankruptcy court upheld the discharge and the Fifth Circuit affirmed. The appeals court said there was no specific information in the record to suggest that Placid knew of any claims related to property it leased from Shelton’s predecessor. The court said no environmental complaints had been made between 1956 and 1986. The court rejected Shelton’s assertion that the environmental damage was easily identifiable since it had taken Shelton six years to notice the damage. Finally, the court noted that Placid had tens of thousands of former leaseholds and it would have been unreasonable to require Placid to give each lessor actual notice of the bankruptcy. In light of this evidence, the appeals court agreed that Shelton’s predecessor was an unknown creditor who was only entitled to notice by publication. This requirement was satisfied when Placid published notice of its bankruptcy on three separate occasions in the Wall Street Journal.

It is unclear of Shelton performed any environmental due diligence prior to acquiring the property. However, a good historical search would have revealed the prior oil leasing activities, could have identified the responsible party and revealed the bankruptcy proceeding. If Shelton had been armed with this information prior to taking title, it could have explored various risk management strategies instead of becoming forced to bear the full brunt of the cleanup.

In Carolyn Vickers Inc. v. Unocal Corp., 2011 Cal. App. Unpub. LEXIS 9642 (Ct. App-2^nd Dist. 12/19/11), Alan Little Ventures (ALV) purchased a 4.1 acre tract of land in San Luis Obispo in 2005. The land had been subdivided into 17 lots by the sellers, Phyllis and Alex Madonna (the “Madonnas”), and was zoned for single family residences.

Four oil pipelines ran across portions of the tract. Back in 1981, an employee of the Madonnas had struck one of the pipelines while operating a backhoe, causing an unknown release of oil.  The oil spill was not properly remediated. The Madonnas did not disclose the presence of the pipelines or the oil spill when they sold the land to ALV.

In 2006, ALV sold lots, ALV sold lots 5 and 9 to Carolyn Vickers Inc. (CVI). One year later, ALV and CVI discovered that soil and groundwater beneath several lots was contaminated, including lot 5. ALV subsequently assigned any rights it had regarding contamination of lots 2 and 4 to CVI who then filed a 69-page complaint containing 16 causes of action for the contamination of the four lots against the companies alleged to have owned or operated the pipelines, namely Unocal Corporation, Union Oil Company of California, Unocal Pipeline Company and Chevron Corporation, Conoco Phillips Company and Conoco Phillips Pipeline Company.  The damages sought by CVI included accrued interest on the purchase mortgages, lost business opportunities and profits, cleanup costs and legal fees.

The defendants moved to dismiss the complaint, asserting the claims stemmed from 1981 and were therefore barred by the three-year statute of limitations. CVI responded that statute of limitations did not begin to run until May 2007 when it learned of the contamination. CVI also argued that even if the discovery rule was inapplicable, the contamination constituted ongoing nuisance and trespass so the statute of limitations had not run for those two causes of action.

The trial court agreed with the defendants that statute of limitations for injury to real property had expired but allowed CVI to amend its continuing nuisance and trespass claims. To expedite an appeal, CVI opted to dismiss its nuisance and trespass claims. This highly risky maneuver proved to be fatal when the appeals court affirmed the ruling of the trial court. The appeals court said that the three-year statute of limitation began to run when the Madonnas first became aware of the oil spill in 1981 and expired in 1984. The court said that statute of limitation was not revived and that ALV or CVI were not entitled to the benefit of the discovery rule because the Madonnas had immediately aware of the oil spill.

This case is yet another example of why environmental due diligence should consider potential impacts from pipelines. Many pipelines were constructed on property that was formally rural but it now prime land for development. Much of the pipeline network is aging, has not been well-maintained and is not well marked. As development encroaches upon pipeline easements, accidents like what happened in this case in 1981 are becoming more frequent.

Unfortunately, due diligence practice has not kept up with this growing concern and phase 1 reports frequently tend to ignore or downplay potential risks about contamination from pipelines. However, in the wake of a number of high profile pipeline leaks during the past few years, pipelines are coming under increasing regulatory scrutiny. Indeed, the GAO issued a report just last week about the potential risks and regulatory gaps for the 250,000 miles of gathering pipelines dispersed across the rural parts of our country.  See http://www.gao.gov/assets/590/589514.pdf?goback=%2Egmp_3607181%2Eanp_3607181_1332819145827_1%2Egmp_3607181%2Egde_3607181_member_103597960 . We are only beginning to understand the potential risks from pipelines and I suspect that pipelines will become the USTs of the 21^st century.

Anyone who has negotiated the purchase of a gas station is aware that these agreements are incredibly complex. The contracts have dense definitions, dependent and inter-related provisions, and grant broad discretion to the sellers in determining the scope and conduct of the cleanup.

A buyer who does not retain an environmental attorney who has previously worked on one of these agreements runs the risk of committing G. Gordy Liddy’s infamous aphorism of being unarmed in the battle of the minds.  The recent decision of D& H Ventures v Exxon Mobil, 2011 Cal. App. Unpub. LEXIS 8580 (Ct.App-2nd^h Div 11/8/11) illustrates this point.

In this case, D&H Ventures purchased a gasoline service station site from Exxon in 1995. D&H was owned by the franchisee that had been operating the property since 1989. Exxon had been remediating the contamination at the property since 1991 and had submitted a summary report to the Los Angeles County Department of Public Works (Regional Board in 1994. The Regional Board eventually issued an NFA letter in October 1997.

The agreement provided that the sale was “as-is” and the purchaser acknowledged that some spills had occurred that resulted in soil or groundwater contamination. Section 10 of the Agreement outlined the parties’ remediation rights and obligations. Exxon was obligated to conduct an environmental site assessment prior to closing and provide the results to the purchaser before closing. If the initial assessment or any additional assessment was unacceptable to D&H, it had the right to terminate the Agreement prior to closing. The environmental assessments served as the “Baseline Condition” for the contamination. If the Regional Board required further testing or remediation, the agreement provided that the Baseline Condition would be amended to reflect the additional sampling. Exxon made no representation or warranty regarding any aspect of any reports delivered to the purchaser and the purchaser had the right to conduct its own investigation.

Exxon was obligated to remediate the Baseline Conditions as it reasonably deemed necessary or appropriate to comply with “Legal Requirements”. Exxon’s remedial obligations under the agreement would be satisfied (1) upon receipt written notice from the appropriate Government Authority that either no further remediation and monitoring of the Baseline Condition was required or (2) when Exxon provided written notice to D&H that remediation had been completed, Exxon had submitted a written request for closure indicating that the soil and/or groundwater had been remediated to the applicable levels but  Government Authority had not provided a written notice within a reasonable time.

The agreement also provided that Exxon was not responsible for investigation or remediation of contamination occurring after the closing date or for increases in contaminant levels above the Baseline Condition.  In addition, the agreement indicated that Exxon’s remediation responsibilities inured only to the benefit of D&H and its lender, and did not extend to subsequent purchasers or assignees.

Exxon agreed to indemnify the purchaser until October 31, 2003 from third parties claims resulting from contamination occurring from Exxon’s use, operation or remediation of the property. However, Exxon would not indemnify purchaser for environmental contamination occurring after closing unless the contamination resulted from the remediation activities or negligence of Exxon. In exchange for the indemnity, purchaser provided a general release for itself, its representatives, successors and assigns except for any obligations of Exxon relating to the Baseline Conditions. The deed conveying title incorporated the environmental provisions of the agreement and provided that the environmental provisions were covenants that ran with the land.

In October 2006, D&H sold the Property to Fry’s Petroleum, Inc (Fry’s). One month later, the Regional Board advised D&H that groundwater contamination had been detected at a former service station site near the property and that the Regional Board was re-opening the case to determine if some of the contamination had migrated from the site. In April 2007, the Regional Board directed both D&H and Exxon to install additional groundwater monitoring wells to determine the direction of groundwater flow and groundwater quality. Exxon refused D&H’s request to resume its assessment and remedial activities at the Property.

D&H then filed its lawsuit, claiming Exxon had breached the agreement and asserting other common law claims. In the breach of contract claim, D&H argued that the 2006 reopener triggered section 10.B providing that if further testing or remediation is required by any government authority, the Baseline Condition would be modified by the results of any such tests. D&H also argued that even if Exxon had no contractual obligation to remediate the Property in 2006, Exxon was not entitled to summary judgment because there were triable issues of fact whether Exxon had breached the Agreement in 1997 and 1998 by failing to properly remediate the contamination.

The trial court rejected all of D&H’s claims and granted summary judgment in favor of Exxon. The court ruled that Exxon had completed its obligations under the agreement when the Regional Board issued the NFA letter. The court said the purchaser was relying on clauses outlining Exxon’s initial assessment obligations as well as pre-closing obligations but not relating to regulatory site closure

Exxon had asserted that D&H’s inadequate remediation claim was barred by the statute of limitations. D&H responded that the discovery rule should have operated to toll the statute of limitations. The court found for Exxon, finding that there was undisputed evidence that D&H was aware of the environmental conditions of the property, including the Baseline Condition, when it purchased the site in 1995, when the application for closure was submitted in 1997 and when Exxon ceased all remediation activities in 1998. The court said that the delayed discovery rule typically did not apply to breach of contract actions, which ordinarily accrue at the time of breach. The trial court also ruled that the broad release clearly and explicitly applied to bar D&H’s the common law claims. Likewise, the court held the release precluded Fry’s claims since the release specifically applied to successors and assigns, and was incorporated into the deed.

The appeals court affirmed. Looking at the entire agreement, the court said the only reasonable construction of the agreement was that the NFA letter relieved Exxon from any further remediation obligation. The court noted that Exxon was required to conduct an assessment, the results of the assessment would establish the Baseline Condition, that Exxon was to remediate the Baseline Condition and that Exxon’s remedial obligations continued until an NFA letter was issued by the appropriate Government Authority. The court said that to impose an indefinite remedial obligation on Exxon for an unidentified period of time was patently inconsistent with the provisions of Section 10 as well as other clauses of the Agreement

On the statute of limitations issue, the appeals court said that even though D&H knew the property was heavily contaminated at the time of purchase, it conducted no independent environmental investigation prior to purchase. Moreover, the court said, the purchaser did not investigate the requirements for site closure when Exxon submitted its request and did not object to Exxon’s representation that it had satisfied all the requirements for site closure. On the basis of this undisputed evidence, the court agreed that the doctrine of delayed discovery did not apply, and that any claim for breach of contract accrued more than 10 years before D&H filed its action

The United States Court of Appeals for the Fifth Circuit recently had the opportunity to explore the scope of the Oil Pollution Act (OPA) third party defense  in Buffalo Marine Services, Inc. v. United States, 663 F.3d 750 (5^th Cir. 2011).

While the OPA third party defense set forth at set forth at 33 U.S.C.S. § 2703(a)(3) was based on the CERCLA Third party defense of 42 U.S.C. 9607(b), the OPA provision has slightly different text.  The appeals court was asked to determine if this textual difference meant that the OPA third party defense was broader than its CERCLA analogue.

This case involved a collision among a barge owned by Buffalo Marine Services, Inc. (“Buffalo Marine”) and the tanker TORM MARY (TORM) during a fuel delivery.  As the barge prepared to dock with the TORM, the barge collided with the TORM, rupturing the tanker’s skin and adjacent fuel-oil tank. Approximately 27,000 gallons of heavy fuel oil spilled into theNechesRiver. Buffalo Marine, the TORM, and their insurers coordinated the clean-up that cost of $10.1 million.

Four parties had been involved in the fuel-purchase transaction. Bominflot, Inc. (“Bominflot”) was the seller of the fuel and LQM Petroleum Services, Inc. (“LQM”) was the broker who arranged the sale and also hired Buffalo Marine to deliver the fuel. Finally, the TORM was the end buyer of the fuel.

OPA has a liability limitation that is based on vessel size. The TORM would have been liable for the first $36 million of clean-up costs under the OPA limitation of liability while the Buffalo Marine barge liability limitation would have been $2MM. Thus, when the owners and insurers of the vessels involved in the spill jointly submitted a request for reimbursement of their cleanup expenses to the Coast Guard’s National Pollution Funds Center(“NPFC”), they identified the Buffalo Marine as the responsible party and sought to invoke the OPA third party defense to the TORM.

The NPFC denied the claim, concluding that the claimants had not established by a preponderance of evidence that there was no contractual relationship between Buffalo Marine and the TORM. In reaching its decision that the TORM was not entitled to the third party defense, the NPFC concluded that the phrase “contractual relationship” did not require direct privity of contract but extended to acts occurring in connection with a commercial fuel delivery even where a chain of agents or contracts stands between the party delivering the fuel and the party receiving the fuel. The NPFC determined the TORM and Buffalo Marine had at least an indirect contractual relationship and that the acts that allegedly caused the spill occurred in connection with that contractual relationship, thereby precluding the third-party defense.

The vessel owners filed a motion for reconsideration with NPFC, arguing that since the OPA third party defense did not refer to “indirect” contractual relationships as the CERCLA third party defense, the OPA defense encompassed indirect contractual relationships. However, the NPFC denied the claimants’ motion for reconsideration. Buffalo Marine and its insurers then sought review in the district court. After the parties filed cross-motions for summary judgment, the district court granted the government’s motion for summary judgment and denied the plaintiffs’ motion for summary judgment. Buffalo Marine and its insurers appealed.

On appeal, the Fifth Circuit noted that while the OPA third party defense did not specify if a third party must be in direct privity of contract with the responsible party to successfully assert the third party defense, the phrase “contractual relationship” was modified with the word “any”. The court said that if the word “any” was to be given its ordinary meaning, the phrase “any contractual relationship” must encompass all varieties of contractual relationships.

The legislative history, the court said, confirmed that Congress meant to encompass indirect contractual relationships with the phrase “any contractual relationship.” The court explained that the version of the OPA originally passed in the House simply referred to “a contractual relationship with a responsible party” while the Senate version had used the same language from the third party defense. At the conference, the court the phrase “any contractual relationship” was substituted for the phrase “a contractual relationship, existing directly or indirectly” and noted that the conference report said that the substitution reflected the adoption of the Senate version of the third-party defense provision, which emphasized the breadth of the “contractual relationship” limitation.

The court also found policy reasons for extending the “contractual relationship” phrase to indirect contractual arrangements. The court said that in determining the meaning of a statute, it must look not only to the particular statutory language but to the design of the statute as a whole as well as its object and policy. The court agreed with the district court that the interpretation advocated by appellants would allow contracting parties to avoid liability by the simple expedient of inserting an extra link or two in the chain of distribution. Allowing responsible parties to escape liability where the third party’s act was in connection with an indirect contractual relationship with the responsible party, the court reasoned, would risk allowing the exception (the third-party defense) to swallow the rule (strict liability for the vessel discharging the oil).

For the foregoing reasons, the court could find no reason to conclude that the phrase “any contractual relationship” excluded indirect contractual relationships. Given the common purposes and shared history of CERCLA and the OPA, the court found the different wording of the two parallel provisions insignificant. Accordingly, the court affirmed the NPFC interpretation of the OPA third-party defense

The court also affirmed the NPFC’s determination that there was an indirect relationship between the TORM and the barge.  The court noted the parties had acknowledged that the TORM contracted with Bominflot to deliver fuel bunkers and that Bominflot had arranged for the bunkers to be delivered by Buffalo Marine’s barge. The e-mails and other communications exchanged among the parties, the court said, supported the conclusion that Buffalo Marine and the TORM thus were linked by a promise of bunkering services in return for payment. While the contractual relationship between the TORM and Buffalo Marine may have been an indirect one, involving a chain of intermediaries, the NPFC reasonably concluded that the arrangement whereby Buffalo Marine’s barge delivered the bunkers to the TORM “squarely falls under the meaning of ‘any contractual relationship

The court also suggested the record included evidence of a more direct contractual relationship between the TORM and Buffalo Marine. The court noted that in the hours leading up to the collision, the master of Buffalo Marine’s tug and the master of the TORM communicated by radio to coordinate the planned delivery. In addition, as Buffalo Marine’s barge and tug were approaching the TORM, the TORM’s chief engineer was preparing the documents that the TORM and Buffalo Marine would have to sign so that the fuel-transfer operation could take place. One of these documents mandated by the OPA rules was a “Declaration of Inspection. Though the spill prevented the parties from ever signing the declaration of inspection, by law, they could not have completed the fuel transfer without signing the declaration. The mere fact that the bunkers were not ultimately delivered, the court said, did not affect the contractual nature of the relationship between the TORM and Buffalo Marine as the approach and collision occurred. Accordingly, the court said the NPFC reasonably concluded that the arrangements for delivery of fuel to the tanker fell within the meaning of “any contractual relationship.”

In the most recent ruling from the court involving 2010 Gulf Oil Spill, the federal district court held that Transocean as owner of the mobile offshore drilling unit (MODU) was only liable for removal costs incurred by the government for discharges of oil that occurred on the surface  while BP and Anadarko were jointly liable for oil that escaped from the blowout preventer (BOP) and remaining segment of the riser pipe as co-lessees.

The federal government had argued that the three defendants were jointly liable under the Oil Pollution Act (OPA) for removal costs and damages resulting from the oil discharges from both the Macando well  (an offshore facility under OPA) and the Deepwater Horizon, an MODU.

The court said that OPA imposes strict liability on responsible parties for removal costs and damages resulting from oil spills. The term “responsible party”  includes persons who own or operate a vessel, or the lessee or permittee of an offshore facility. The court noted that an MODU could be both a vessel or an offshore facility. When an MODU is being moved from one drilling location to another, the court said the MODU would be considered a vessel for OPA liability purposes. However, when it being used to drill or explore for oil) it is considered to be an offshore facility. When an oil discharge occurs beneath the surface while the MODU is being used as an offshore facility, the court said the responsible party is the lessee. However, when the MODU is being used as an offshore facility and the oil discharge occurs on the water surface, the responsible party is the owner or operator of the MODU up to the limitation of liability for vessels (based on gross tonnage). Any liability above that limit would be borne by the lessee.

Accordingly, because the Deepwater Horizon was being used as an offshore facility at the time of the oil spill, the court held that Transocean as owner/operator of the MODU was not a responsible party under OPA for oil discharges that occurred beneath the surface of the water from the BOPor riser.

Under OPA, the liability limitations do not apply if the oil discharge is proximately caused by gross negligence, wilful misconduct or violation of federal safety, construction and operating rules. The court also ruled that the government was not entitled to summary judgment on the issue of unlimited liability.

In re: Oil Spill by the Oil Rig “Deepwater Horizon” in the Gulf of Mexico on April 20, 2010, 2012 U.S.Dist. LEXIS 21795(E.D.La. 2/22/12)

Many commercial properties are subject to old leases that were originally negotiated prior to the advent of environmental laws. These leases not only do not address environmental issues but also may contain clauses that can create liability for landlords when the property contains USTs.

One of the more problematic clauses in old leases are those that provide that property left behind when a tenant surrenders the premises becomes the property of the landlord. When a tenant fails to remove a UST, these clauses can result in the landlord becoming responsible for taking corrective action as the owner of the UST.

A case that illustrates this issue is The Carroll Independent Fuel Company v Washington Real Estate Investment Trust, 2011 Md. App. LEXIS 161 (Ct. Special App. 12/1/11), the plaintiff (CIF), a wholesale distributor of motor fuels, entered into a ten-year commercial lease agreement with defendant (WRIT) in July 1988 to lease a gasoline service station in Westminster, Maryland. Approximately one year later, CIF and WRIT entered into another ten-year commercial lease agreement for an adjacent gasoline service station. An addendum to the lease required CIF to install new gasoline tanks at each of the leased properties.

Both leases required CIF to remove all of its personal property and unattached movable trade fixtures prior to surrendering the premises. If CIF failed to remove its personal property and trade fixtures, the leases provided that such property would be considered abandoned and become the exclusive property of WRIT. The leases also required CIF to provide an environmental inspection certificate declaring that the “Demised Premises” were “free of dangerous and/or toxic substances or materials in quantities or concentration which would require clean up under applicable governmental regulations”.

In July 2005, CIF provided notice to WRIT that it would be terminating the leases effective August 15, 2005. CIF had sought to renegotiate the leases and modernize the properties but WRIT declined, explaining that it had decided to demolish the buildings to facilitate leasing of the properties to a bank.  After CIF vacated the premises, WRIT advised CIF it had failed to remove the USTs or provide the environmental inspection certification required upon termination of possession.” As a result, WRIT told CIF that that until these conditions were satisfied, WRIT would consider CIF not to have surrendered possession of the premises and would reserved its right under the leases to collect daily holdover fees.

Between January 30 and February 1, 2006, CIF removed the gasoline storage tanks and removed tons of contaminated soil. CIF continued to corrective action until March 2007 when it ceased work. At this point, WRIT took over remediation of the property. In May 2007, WRIT combined the two sites and leased it to Susquehanna Bank. Demolition of the service station buildings was completed in October 2007.

WRIT filed breach of contract claims for each lease. WRIT alleged, inter alia, that CIF had failed to keep the properties in the condition required by law due to the petroleum contamination and it failed to surrender possession of the properties as required by the leases. WRIT requested a judgment of $3,000,000, consisting of rent at the holdover rate and additional damages, including attorneys’ fees and costs and expenses associated with remediation.

CIF responded that there was no evidence that any spills or contamination had occurred during its occupancy and that it did not provide the environmental inspection certificate because  it was limited to the condition of the buildings and felt the certification was unnecessary since WRIT was going to demolish the buildings. On the claim for holdover rent, CIF said it did not initially remove the USTs because it believed that ownership of the tanks vested in WRIT upon termination of the lease. CIF also said when it subsequently discovered that WRIT never registered the tanks in its name, CIF decided to remove the tanks between in January 2006. CIF continued to pay base rent for both properties during that time.

In January 2010, the circuit court ruled that CIF was not liable for environmental contamination that predated its tenancy and that WRIT had not shown that CIF caused the contamination of the sites. The court also refused to award damages for lost rent since there was evidence that construction could have occurred while remediation efforts were occurring.

Turning to the holdover rent issue, the court rejected CIF’s argument that the tanks were to become WRIT’s property under the lease because CIF was aware that WRIT was not interested in leasing the property for a gasoline station but wanted to convert it to a bank. Accordingly, the court found that CIF was holding over from September 2005 through January 2006, and WRIT was entitled to holdover rent for that period of time in the amount of $123,460.81

However, the court agreed with CIF that its duty under environmental certification clause was only to have an inspector certify that the buildings themselves were free from hazardous waste and did not extend to the soil or groundwater contamination. Thus, the court concluded that WRIT was entitled to charge holdover rent until CIF could certify that they had not left the demised premises in a dangerous state. The court found CIF liable to WRIT for holdover rent from September 2005 through October 2007, when the buildings were demolished, in the amount of $624,621.09

The appeals court reversed the judgment for holdover rent.  The appeals court said the record reflected that WRIT was the owner of the tanks and therefore the failure of CIF to remove property owned by the landlord did not constitute holding over.  On the environmental certification, the appeals court CIF’s failure to deliver the certificate may have constituted a breach of the lease but there was no evidence that CIF’s failure interfered with WRIT’s possession and control of the premises. However, the court awarded WRIT reasonable attorneys fees for the breach of the lease.

As the trial date for the sprawling Deepwater Horizon Gulf Oil Spill litigation date rapidly approaches, the federal district court has been busy issuing decisions to help refine the issues. Two of these opinion involved interpreting the scope of contractual indemnities-one of our favorite topics.

The first opinion involved cross-motions for partial summary judgment filed by BP and Transocean (RIG).  In re Oil Spill by the Oil Rig “Deepwater Horizon, 2012 U.S. Dist. LEXIS 9005 (E.D. La. 1/26/12). The claims arose from related litigation, In re Triton Asset Leasing GmbH, et al., that was instituted by RIG  as owner of the DEEPWATER HORIZON pursuant to the Limitation of Shipowners’ Liability Act, 46 U.S.C. § 30501, et seq to address claims filed against Transocean for personal injury, wrongful death, economic loss, property damage, etc. RIG, in turn, impleaded BP. The second related action was U.S. v. BP Exploration & Prod. Inc., et al., No. 10-4536 where the United States asserted claims for civil penalties under Section 311(b)(7) of the Clean Water Act  (“CWA”) and a declaration of liability for removal costs and damages under the Oil Pollution Act of 1990 (“OPA”). BP and RIG  were named as defendants  and filed cross-claims against each other.

As readers no doubt recall, predecessors to BP and RIG entered into a drilling contract in 1998 where RIG agreed to build a mobile offshore drilling unit (“MODU”) that BP agreed to hire for drilling activities on the outer continental shelf. The drilling contract contained several indemnity clauses allocating liability for certain risks and releasing the other party from claims associated with those risk. In particular, Articles 24.1 and 24.2 addressed pollution risks while Article 25.1  broadly defined the scope of the indemnity obligation. In general, Article 24.1 allocated to RIG for risks associated with pollution originating on or above surface waters with Article 24.2 allocating to BP pollution risk “not assumed by” RIG (i.e., pollution originating beneath the water’s surface). Article 25.1 generally applied to indemnity clauses that contained the phrase “shall protect, release, defend, indemnify and hold harmless” but did not apply “to the extent any such obligation is specifically limited to certain causes elsewhere in this contract.”

RIG asserted in its motion that BP was required under their drilling agreement to defend and indemnify RIG from claims and liabilities related to pollution originating below the surface of the water even if Transocean was strictly liable or if the pollution was caused by RIG’s negligence or gross negligence. RIG also asserted that the scope of BP’s indemnity obligation extended to compensatory damages, punitive damages, and statutory penalties. RIG argued that broad indemnity of Article 25.1 applied to Article 24.2, because Article 24.1 did not  contain language specifically limiting indemnity coverage to certain causes after it used the “shall protect” phrase. However, RIG admitted that the drilling contract did not provide indemnity for intentional or willful misconduct.

Meanwhile, BP denied that it owed indemnity for claims based on strict liability such as for claims under OPA or the CWA where RIG acted with gross negligence. Specifically, BP argued that the last sentence of Article 24.2 limited its indemnity obligation to instances where subsurface pollution is caused by Transocean’s “negligence or fault”, and because of this specific limitation Article 25.1. BP also argued that even if RIG’s interpretation was correct, contractual indemnities that purport to include gross negligence, punitive damages, or CWA civil penalties were unenforceable on public policy grounds. Finally, BP also argued that the indemnity clause was void if RIG breached the drilling contract or materially increased risks to BP.

After considering the language of the contract and the applicable law, the court agreed with RIG that Article 24.2 did not specifically limit the application of Article 25.1. The court said Article 25.1 provided broad indemnity coverage wherever the “shall protect” triggering phrase appeared. The court said the broad indemnity coverage would apply unless the exclusionary phrase “except . . . specifically limited” was contained in the particular indemnity provision. The court noted the specific exclusionary phrase appeared in Articles 22.3 and 23.1 but not in Article 24.2. Absent language that specifically limited Article 25.1, the court said it could be reasonably inferred that the parties intended that Article 25.1 would be fully incorporated into Article 24.2, and did not operate to exclude gross negligence, strict liability, or other causes or damages. The court also said this was consistent with the plain language of Article 24.2 providing that BP would  assume “any” liability not assumed by RIG in Article 24.1

Having ruled on the meaning of the indemnity, though, the court then said that RIG was not legally entitled to indemnity for the full range of liabilities listed in Article 25. The court said that cases holding that public policy prohibited a party from being indemnified for its own gross negligence were not applicable because the cases cited by the parties dealt with “release” or “exculpatory clauses”, and not indemnities. The court said there was a tension between the policy of freedom of contract, which weighs in favor of enforcing the indemnity, and a reluctance to encourage grossly negligent behavior, which weighs against enforcing the indemnity the freedom of contract. The reciprocal nature of these indemnity clauses arguably created an incentive for RIG to avoid grossly negligent conduct, or at least did not encourage RIG to act in a grossly negligent manner, the court said which favored enforcing the clause. In addition, the court said, the agreement reflected an attempt by sophisticated entities engaged in a potentially lucrative and obviously risky endeavor to allocate risk ahead of time, ostensibly in the hopes that some degree of certainty may be brought to the risks inherent in that undertaking.

The court found further support from OPA the primary source of the compensatory damages arising from oil pollution. The court observed that OPA section 2710 expressly permitted contractual indemnity but was silent if such indemnity may include gross negligence. In contrast, the court said, OPA section 2716(f)(1) states that a responsible party’s “guarantor” may raise as a defense that the responsible party acted with “willful misconduct,” but not gross negligence. The court acknowledged that while section 2716(f)(1) might involve different policy concerns it nonetheless served as another indication that OPA is not opposed to indemnification for gross negligence.

Thus, the Court held that if RIG committed gross negligence that caused pollution originating below the surface of the water, public policy would not bar its claim for contractual indemnity from BP. 16 However, the court explained its holding was limited to compensatory damages, and did not include any punitive damages which  might arise if Transocean is found grossly negligent.

RIG also asserted that CWA civil penalties should be covered by the indemnity because they were primarily remedial in nature. RIG also argued that the CWA section 1321 expressly allowed contractual indemnification and to the extent the statute does not apply, indemnification is allowable under OPA 2710. The court observed that CWA secton 1321(b)(7) imposes a civil penalty for discharges of a “harmful” quantity of oil discharges and that the penalties were increased for gross negligence or willful misconduct. The court also noted the legislative history and case law suggested that civil penalty provision has multiple goals, including restitution but that the primary objectives are to punish and deter future pollution. Thus, the court held that public policy invalidated the drilling contract’s indemnity clause to the extent it included civil penalties.

Finally, the court rejected RIG’s claim that BP had a duty to defend much like under an insurance policy. The court said while insurance contracts are a type of indemnity contract, the similarities were different (to quote Dale Berra-Yogi Berra’s son). The court said the purpose of an insurance contract is to distribute risk of loss across a large group, are usually not negotiated., and any ambiguities are construed in favor of the insured. By contrast, the court explained, an indemnity clause contained in a non-insurance contract is construed against coverage, because the agreement creates duties that differs or extends beyond those established by general principles of law. Such clauses are typically collateral or incidental to a contract that has a principal purpose other than risk shifting. The court said Article 25.1 did not contain any express language that the duty to defend was broader than indemnity. Since Article 25.1 listed the duty to defend in the same sentence as the duty to indemnify the court said this reflected that the duties to defend and indemnify are to be treated identically. Because these duties are co-extensive, and the extent to which RIG is owed indemnity was not entirely clear at the moment, the scope of the duty to defend also could be determined. Accordingly, the court held that BP’s duty to defend only required it to reimburse RIG’s defense costs after there has been judicial determination on the merits.

The second opinion involved cross-motions for summary judgment by both BP and Halliburton in a decision issued on January 31^st. In re Oil Spill by the Oil Rig “Deepwater Horizon, 2012 U.S. Dist. LEXIS 10952 (E.D. La. 1/31/12). Halliburton asserted that BP was required to defend and indemnify Halliburton against any and all claims related to a blowout or uncontrolled well condition and relating to pollution and/or contamination from the reservoir. BP’ sought a ruling that it was not required to indemnify Halliburton for punitive damages, fines, or penalties. Additionally, BP opposed Halliburton’s motion on the grounds that Halliburton committed fraud, breached the contract, and/or materially increased risks to BP as indemnitor, and such acts discharge BP’s indemnity obligations

The indemnity provisions were contained in clause 19 of the agreement. Like the drilling contract between RIG and BP, the contract between Halliburton and BP contained reciprocal indemnities where Halliburton assumed certain liabilities for pollution emanating from its equipment above the surface. However, a significant difference was that BP expressly agreed in clause 19.7(a) to indemnify Halliburton for its gross negligence. BP did not dispute the language but focused on whether public policy permits such indemnification.

For the same reasons as in the RIG decision, the court said that if CWA civil penalties were indirectly asserted against Halliburton via equitable contribution or indemnity, BP would not have a contractual obligation to indemnify Halliburton for public policy reasons. Likewise, the court held that BP did not owe Halliburton indemnity for punitive damages.

Finally, BP alleged that Halliburton made fraudulent statements and fraudulently concealed material information concerning the cement tests it conducted, and that BP relied on these statements when it allowed Halliburton to pour the unstable cement slurry that led to the uncontrollable well and blowout. BP asserted that the language of the indemnity  did not extend to fraud, nor would public policy permit such indemnification, given that fraud involves willful misconduct exceeding gross negligence. Halliburton denied that it committed fraud and asserted that BP’s allegations were merely breach of contract claims cloaked as fraud. In any event, Halliburton argued that Clause 19.7 was broad enough to include fraud.

The Court agreed that fraud could void an indemnity clause on public policy grounds, given that it necessarily includes intentional wrongdoing. The Court also said that a mere failure to perform contractual obligations as promised did not constitute fraud. However, since there were material issues of fact,  the Court denied ruling on this aspect of the summary judgment motions.